Eni
Annual
Rep ort
2019
Index
2 |
M A N A G E M E N T R E P O R T
Activities
Business model
Responsible and sustainable approach
Letter to shareholders
Eni at a glance
Stakeholders engagement activities
Strategy
Integrated Risk Management
Governance
Operating review
Exploration & Production
Gas & Power
Refining & Marketing and Chemicals
Corporate and other activities
Financial review and other information
Financial review
Risk factors and uncertainties
Outlook
Consolidated disclosure of non-financial information (NFI)
Other information
Glossary
3
4
5
6
12
14
16
20
24
30
49
54
60
63
88
105
106
140
141
1 4 3 |
C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S
2 7 5 |
A N N E X
CONSOLIDATED DISCOLOSURE OF NON-FINANCIAL INFORMATION
This Annual Report includes the consolidated disclosure of non-financial information (NFI), prepared in accordance with Legislative Decree
No. 254/2016, relating to the following topics:
˙ environment;
˙ social;
˙ people;
˙ human rights;
˙ anti-corruption.
The disclosure on these topics and KPIs included in this report are defined in accordance with the “Sustainability Reporting Standards”
published by the Global Reporting Initiative (GRI Standards).
INTEGRATED ANNUAL REPORT
Eni’s 2019 Annual Report is prepared in accordance with principles included in the “International Framework”, published by International Integrated
Reporting Council (IIRC). It is aimed at representing financial and sustainability performance, underlining the existing connections between
competitive environment, group strategy, business model, integrated risk management and a stringent corporate governance system.
ˇ
FINANCIAL HIGHLIGHTS
Sales from operations
Operating profit (loss)
Adjusted operating profit (loss)(a)
Adjusted net profit (loss)(a)(b)
Net profit (loss)(b)
Net cash flow from operating activities
Capital expenditure
of which: exploration
development of hydrocarbon reserves
Dividend to Eni's shareholders pertaining to the year(c)
Cash dividend to Eni's shareholders
Total assets at year end
Shareholders' equity including non-controlling interests at year end
Net borrowings at year end before IFRS 16
Net borrowings at year end after IFRS 16
Net capital employed at year end
of which: Exploration & Production
Gas & Power
Refining & Marketing and Chemicals
Share price at year end
Weighted average number of shares outstanding
Market capitalization(d)
(a) Non-GAAP measures.
(b) Attributable to Eni’s shareholders.
(c) The amount of dividend for the year 2019 is based on the Board’s proposal.
(d) Number of outstanding shares by reference price at year end.
SUMMARY FINANCIAL DATA
Net profit (loss)
- per share(a)
- per ADR(a)(b)
Adjusted net profit (loss)
- per share(a)
- per ADR(a)(b)
Cash flow
- per share(a)
- per ADR(a)(b)
Adjusted Return on average capital employed (ROACE)
Leverage before IFRS 16
Leverage after IFRS 16
Gearing
Coverage
Current ratio
Debt coverage
Net Debt/EBITDA adjusted
Dividend pertaining to the year
Total Share Return (TSR)
Dividend yield(c)
(€ million)
(€)
(million)
(€ billion)
(€)
($)
(€)
($)
(€)
($)
(%)
(€ per share)
(%)
2019
69,881
6,432
8,597
2,876
148
12,392
8,376
586
5,931
3,089
3,018
123,440
47,900
11,477
17,125
65,025
53,358
2,744
10,387
13.9
3,592.2
50
2018
75,822
9,983
11,240
4,583
4,126
13,647
9,119
463
6,506
2,989
2,954
118,373
51,073
8,289
n.a.
59,362
50,358
3,143
7,371
13.8
3,601.1
50
2017
66,919
8,012
5,803
2,379
3,374
10,117
8,681
442
7,236
2,881
2,880
114,928
48,079
10,916
n.a.
58,995
49,801
3,394
7,440
13.8
3,601.1
50
ˇ
2019
2018
2017
0.04
0.09
0.80
1.79
3.45
7.72
5.3
24
36
26
7.3
1.2
72.4
100.7
0.86
6.7
6.3
1.15
2.72
1.27
3.00
3.79
8.95
8.5
16
n.a.
14
10.3
1.4
164.6
45.2
0.83
4.8
5.9
0.94
2.12
0.66
1.49
2.81
6.35
4.7
23
n.a.
18
6.5
1.5
92.7
80.6
0.80
(5.6)
5.7
(a) Fully diluted. Ratio of net profit/cash flow and average number of shares outstanding in the period. Dollar amounts are converted on the basis of the average EUR/USD exchange rate quoted
by Reuters (WMR) for the period presented.
(b) One American Depositary Receipt (ADR) is equal to two Eni ordinary shares.
(c) Ratio of dividend for the period and the average price of Eni shares as recorded in December.
EMPLOYEES
Exploration & Production
Gas & Power
Refining & Marketing and Chemicals
Corporate and other activities
Group
INNOVATION
R&D expenditure
Digital transformation expenditure
First patent filing application
(number)
2019
11,502
3,015
11,291
6,245
32,053
2018
11,645
3,040
11,136
5,880
31,701
2017
11,970
4,313
10,916
5,735
32,934
(€ million)
(number)
2019
194
105
34
2018
197
86
43
2017
185
n.a.
27
(total recordable injuries/worked hours) x 1,000,000
HEALTH, SAFETY AND ENVIRONMENT
TRIR (Total Recordable Injury Rate)
of which: Exploration & Production
employees
contractors
Gas & Power
employees
contractors
Refining & Marketing and Chemicals
employees
contractors
Corporate and other activities
employees
contractors
Direct GHG emissions (Scope 1)
of which: CO2 equivalent from combustion and process
CO2 equivalent from flaring
CO2 equivalent from venting
CO2 equivalent from methane fugitive emissions
Direct GHG emissions - Exploration & Production
Direct GHG emissions - Gas & Power
Direct GHG emissions - Refining & Marketing and Chemicals
GHG emissions/100% operated hydrocarbon gross production (upstream)
Volumes of hydrocarbon sent to flaring
Total volumes of oil spills (> 1 barrel)(a)
of which: due to sabotage
operational
Reinjected production water
Groundwater treated at TAF plants and used in the production cycle or reinjected (Eni Rewind)
Groundwater used in the production cycle/reinjected vs. total treated groundwater (Eni Rewind)
Recovered waste vs. recoverable waste (Eni Rewind)
(a) In line as reported on page 122.
(mmtonnes CO2 eq)
(tonnes CO2 eq/kboe)
(billion Sm3)
(barrels)
(%)
(mmcm)
(%)
2019
0.34
0.33
0.18
0.37
0.59
0.46
0.84
0.27
0.24
0.29
0.51
0.20
1.01
41.20
32.27
6.49
1.88
0.56
22.75
10.47
7.97
19.58
1.9
7,258
6,222
1,036
58
5.1
19
59
2018
0.35
0.30
0.29
0.30
0.56
0.34
0.99
0.56
0,49
0.62
0.53
0.55
0.48
43.35
33.89
6.26
2.12
1.08
24.06
11.08
8.19
21.44
1.9
6,687
4,022
2,665
60
4.8
21
58
2017
0.33
0.28
0.23
0.30
0.37
0.45
0.23
0.62
0,56
0.69
0.41
0.21
1.00
43.15
33.03
6.83
2.15
1.14
24.02
11.30
7.82
22.75
2.3
6,559
3,236
3,323
59
4.2
21
48
OPERATING DATA
EXPLORATION & PRODUCTION
Hydrocarbon production
Net proved reserves of hydrocarbons
Reserve life index
Organic reserve replacement ratio
Profit per boe(a)
Opex per boe(b)
Finding & Development cost per boe(c)
GAS & POWER
Worldwide gas sales
of which: Italy
outside Italy
LNG sales
Installed capacity power plants
Electricity produced
Electricity sold
REFINING & MARKETING AND CHEMICALS
Retail sales of petroleum products in Europe
Retail market share in Italy
Service stations in Europe at year end
Average throughput of service stations in Europe
Refinery throughputs on own account
Average refineries utilization rate
Capacity of biorefineries
Production of biofuels
Production of petrochemical products
Average chemical plant utilization rate
(a) Related to consolidated subsidiaries.
(b) Includes Eni’s share in joint ventures and equity-accounted entities.
(c) Three-year average.
2019
2018
2017
(kboe/d)
(mmboe)
(years)
(%)
($/boe)
(bcm)
(GW)
(TWh)
(mmtonnes)
(%)
(number)
(kliters)
(mmtonnes)
(%)
(ktonnes/year)
(ktonnes)
(%)
1,871
7,268
10.6
92
5.1
6.4
15.5
73.07
37.85
35.22
10.1
4.7
21.66
39.49
8.25
23.7
5,411
1,766
22.74
88
660
256
8,068
67
1,851
7,153
10.6
100
9.3
6.8
10.4
76.71
39.03
37.68
10.3
4.7
21.62
37.07
8.39
24.0
5,448
1,776
23.23
91
360
219
9,483
76
1,816
6,990
10.5
103
8.7
6.6
10.4
80.83
37.43
43.40
8.3
4.7
22.42
35.33
8.54
24.3
5,544
1,783
24.02
90
360
206
8,955
73
Eni
Annual
Report
2019
Disclaimer
This Annual Report contains certain forward-looking statements in particular under the section “Outlook” regarding capital expenditures, dividends, buy-back programs, allocation
of future cash flow from operations, financial structure evolution, future operating performance, targets of production and sale growth and the progress and timing of projects.
By their nature, forward-looking statements involve risks and uncertainties because they relate to events and depend on circumstances that will or may occur in the future. Actual
results may differ from those expressed in such statements, depending on a variety of factors, including the timing of bringing new oil and gas fields on stream; management’s ability
in carrying out industrial plans and in succeeding in commercial transactions; future levels of industry product supply; demand and oil and natural gas pricing; operational problems;
general macroeconomic conditions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations; development and use of new
technology; changes in public expectations and other changes in business conditions; the actions of competitors. “Eni” means the parent company Eni SpA and its consolidated
subsidiaries.
2
Mission
We are an energy company.
We concretely support a just energy transition,
with the objective of preserving our planet
and promoting an efficient
and sustainable access to energy for all.
Our work is based on passion and innovation,
on our unique strengths and skills,
on the equal dignity of each person,
recognizing diversity as a key value for human development,
on the responsibility, integrity and transparency of our actions.
We believe in the value of long-term partnerships
with the Countries and communities where we operate,
bringing long-lasting prosperity for all.
The new mission represents more explicitly the Eni’s path to face the global challenges, contributing to achieve the
SDGs determined by the UN in order to clearly address the actions to be implemented by all the involved players.
THE SUSTAINABLE DEVELOPMENT GOALS
Global goals for a sustainable development
The 2030 Agenda for Sustainable Development, presented in September 2015, identifies the 17 Sustainable
Development Goals (SDGs) which represent the common targets of sustainable development on the current complex
social problems. These goals are an important reference for the international community and Eni in managing
activities in those Countries in which it operates.
3
Activities
Eni is an energy company, operating in 66 Countries with about 32,000 employees.
Eni engages in oil and natural gas exploration, fields development and production, mainly in Italy, Algeria, Angola, Australia, Congo, Egypt,
Ghana, Kazakhstan, Libya, Mexico, Mozambique, Nigeria, Norway, Oman, the United Arab Emirates, the United Kingdom and the United
States, for overall 41 Countries.
Eni sells gas, electricity, LNG and oil products in European and extra-European markets, also leveraging on trading activities. Products
availability is ensured by oil and gas production in the upstream business, long-term gas supply contracts, CCGT power plants, Eni's
refinery system as well as by Versalis' chemical plants. The supply of commodities is optimized through trading activity.
Integrated business units enable the company to capture synergies in operations and reach cost efficiencies.
Eni engages in the renewable energy business through the development of plants for the production of green energy, also reconverting
industrial sites through safety, remediation and environmental restoration.
OFFSHORE
DEVELOPMENT
EXPLORATION
PRODUCTION
OIL AND GAS
FIELDS
SUPPLY OF
GREEN SOURCES
REFINERIES AND
PETROCHEMICAL
PLANTS
(traditional and bio)
FUEL/BIOFUEL
TRADING
& SHIPPING
INTERNATIONAL
OIL AND GAS
MARKETS
CHEMICAL
PRODUCTS
/BIO-BASED
CHEMICALS
LIQUEFYING GAS
TRANSMISSION
NETWORK
LUBRICANTS
ONSHORE
DEVELOPMENT
RIGASSIFYING LNG
LONG-TERM
NATURAL GAS
SUPPLY
CONTRACTS
PORTFOLIO
GAS AND
POWER
RENEWABLE
ENERGY
PRODUCTION
POWER
GENERATION
REMEDIATION, WATER & WASTE INTO DEVELOPMENT
B2B
B2C
Operating in
66 Countries
Eni is an integrated energy company looking to the long-term, aiming to play a decisive role in the
energy transition to a low carbon future. The main challenge of our industry is to ensure universal
access to energy, efficiently and sustainably, combating climate change, maximizing the energy
efficiency of its assets and total elimination of flaring and methane leaks, the growth of low carbon
sources in its portfolio; zero-emission sources development and the development of circular economy
initiatives.
The circular transformation of Eni has been started-up in the downstream businesses, with the first
conversion in the world of a traditional refinery in biorefinery, the transformation of waste in energy
products, leveraging on proprietary technologies such as the Waste To Fuel and on the realization in the
chemical business of new processes and products transforming waste plastics in second raw
material. Consolidated skills, technologies, innovation and research geographical differentiation of
assets are the levers to strengthen a changing based on the synergies among stakeholders, the
industrial symbiosis and the cultural change.
ATTIVITÀ DI ENIEni Relazione Finanziaria Annuale 2019 4
Business model
Eni’s business model is focused on creating value for its
stakeholders and shareholders through a strong presence
along the whole value chain. Eni, as an integrated energy
company, contributes, directly or indirectly, to achieve
the goals of Sustainable Development (SDGs) of the UN
2030 Agenda, supporting a socially equal energy transition
responding through concrete, quick and economically
sustainable answers to the challenge of combating climate
change and giving access to the energy resources in an
efficient and sustainable way, overall. To manage this
effectively, Eni integrates organically its industrial plan with the
principles of environmental and social sustainability, enlarging
its actions along three directives:
1. operational excellence,
2. carbon neutrality in the long term,
3. alliance for development.
VALUE CREATION FOR STAKEHOLDER AND SHAREHOLDER
THROUGH AN INTEGRATED PRESENCE ALL ALONG THE ENERGY VALUE CHAIN
OPERATIONAL EXCELLENCE
Hse, Human Rights & Integrity
Efficiency
Resilience
Capital discipline
FLEXIBLE PORTFOLIO
EVOLUTION
AND ORGANIC GROWTH
CARBON NEUTRALITY
IN THE LONG-TERM
Life cycle GHG emissions
approach
Set of concrete levers for
portfolio decarbonisation
ALLIANCE
FOR DEVELOPMENT
Dual Flag approach
Public-private partnership
Jobs creation and
know-how transfer
NET CARBON EMISSIONS
AND NET
CARBON INTENSITY REDUCTION
LOCAL DEVELOPMENT
PROGRAMME IN ACCORDANCE
WITH 2030 AGENDA
COMPETENCES, TECHNOLOGIES AND DIGITALIZATION
1. Firstly, Eni’s business is constantly focused on the operational
excellence. This is translated into:
• a continuous commitment to the valorization of people and, in
HSE, to the safeguard of health and safety and environmental
protection;
• the efficiency and resilience of operations, thanks to which
Eni has accelerated projects’ time-to-market, reducing their
break-even;
• a solid financial discipline;
• the maximum attention to the integrity and respect for
human rights.
The Company will leverage on these drivers to catch the opportunities
deriving from the possible evolution of the energy market and
technological progress and to grow organically.
2. Secondly, Eni’s business model envisages a path to decarbonization
with the ambition to lead the Company to become carbon neutral in
the long-term.
In this context, the Company adopts a life cycle GHG emissions
approach and leverage on a set of actions including:
maximizing the energy efficiency of its assets; growing low carbon
sources in its portfolio (with an increase in gas and bio-fuel share,
as well as the production and marketing of bio-methane); growing
emission-free sources and developing circular economy initiatives.
An important role will also be played by the application of new
technologies capturing CO2 and the development of forestry projects
for the forest conservation in accordance with the REDD+ scheme.
This approach and these drivers will enable Eni to considerable
reduce its carbon footprint, both in terms of net emissions and
carbon intensity.
3. Thirdly, Eni’s value creation will leverage on the alliances
for the promotion of local development in its Countries
of operation. Eni is not only committed to address the
valorization of resources of producing Countries, allocating
their gas production to the local market and facilitating
access to electricity, but also to promote a wide range of
community initiatives: from diversification of local economies,
to health projects, education, access to water and hygiene.
This distinctive approach, called Dual Flag, is based on
collaborations with institutions, cooperation agencies and local
stakeholders in order to identify certain necessary actions
to meet the needs of communities in line with the National
Development Plans and the 2030 UN Agenda.
Eni is also committed to creating employment opportunities and
transfers its know-how and expertise to its local partners involved
in operations.
These distinctive factors are reflected in the Local Development
Programs (LDP) in line with the 2030 UN Agenda and consistent
with the National Development Plans to foster an inclusive growth,
creating long-term value. Initiatives identified in Eni’s Countries
of operations leverage on an integrated approach through public-
private partnerships and alliances with other internationally
recognised players engaged in the territory.
Eni’s business model is designed on these three levers leveraging on
internal competences, the deployment of innovative technologies
and the digitalization process.
Responsible and sustainable approach
For Eni, a responsible and sustainable approach is the rationale for
creating value in the medium and long term for the company and for all
stakeholders. This approach is emphasized in the new corporate
Mission, which expressly embodies the transformation path
undertaken by Eni to play a decisive role in the global process of a "just
transition" towards a low-carbon future, facilitating access to energy
in an efficient and sustainable way for all and contributing to the
achievement of the Sustainable Development Goals (SDGs).
5
SUSTAINABLE
DEVELOPMENT GOALS
COMBATING
CLIMATE
CHANGE
COMMITMENTS
MAIN RESULTS IN 2019
Eni has defined a medium- and
long-term plan in order to take full
advantage of the opportunities
offered by energy transition and
to reduce progressively the
carbon footprint of its activities
• -27% of GHG emission intensity index (upstream)
vs. 2014
• -29% volumes of hydrocarbons sent to process
flaring vs. 2014
• -81% upstream fugitive methane emissions vs.
2014
(TARGET REACHED)
PEOPLE
SAFETY
RESPECT
FOR THE
ENVIRONMENT
HUMAN
RIGHTS
Eni is committed to supporting
the transition by consolidating
and developing skills, enhancing
every psychophysical dimension
of its people and recognising
diversity as a resource
• 32,053 employees in service as of December, 31
(reported +1.1% vs 2018, adjusted(a) 2.0% vs. 2018)
• +3.2 percentage point increase in women hired (32.3%
in 2019 vs. 29.1% in 2018)
• Approx. 1.4 million hours of training (+16.5% vs. 2018)
• 12,000 professional profiles mapped to date
Eni believes that safety in the
workplace is an essential value to
be shared among employees,
contractors and local stakeholders
and it is committed to eliminating
the occurrence of incidents
Eni promotes the efficient use of
natural resources and the
safeguard of protected areas
relevant to biodiversity,
identifying potential impacts and
mitigation actions and is
committed not to carry out
hydrocarbon exploration and
development activities in UNESCO
World Heritage Natural Sites
Eni is committed to respecting
Human Rights in its activities
and to promoting their respect
among its partners and
stakeholders
• TRIR(b) 0.34
• TRIR -3% vs. 2018 (-52% vs. 2014)
• Formalisation of Eni's commitment not to carry out
exploration and development activities in UNESCO
World Heritage Natural Sites
• Extension of biodiversity risk mapping to all business
lines
• Eni's adhesion to the CEO Water Mandate
• 89% reuse of freshwater
• -12% seawater withdrawn vs. 2018
• -15% waste from production activities generated vs. 2018
• -61% operational oil spills vs. 2018
• First “Eni for Human Rights” report published
• Ranked in the top 4% of the 200 companies
evaluated by the CHRB(c)
• “CEO Guide to Human Rights” of the WBCSD(d) signed
• 97% security contracts with Human Rights clauses
• 100% new suppliers assessed according to social
criteria
TRANSPARENCY
AND INTEGRITY
IN BUSINESS
MANAGEMENT
Eni carries out its business activities
with fairness, correctness,
transparency, honesty and integrity
in compliance with the law
•Membership in EITI(e) since 2005
• 9 countries where Eni supports EITI’s local
Multi-Stakeholder Group
• 27 audits with anti-corruption checks
COOPERATION
MODEL
The cooperation model integrated
into the business model is a
distinctive feature of Eni, which
aims to support countries in
achieving their development
goals.
• €95.3 million invested in local development
• Partnership signed with UNIDO to contribute to SDG 9
• MoUs signed with Angola and Mozambique that
combine traditional business with a commitment
to diversified and sustainable growth
M
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O
TECHNOLOGICAL
INNOVATION
For Eni, research, development
and rapid implementation of new
technologies are an important
strategic lever to drive business
transformation.
• €194 million invested in research and
technological development
• 34 applications for first patent filings, of which 15
concern renewable sources
(a) Growth with the same consolidation structure, mainly due to the sale of Agip Oil Ecuador.
(b) Total Recordable Injury Rate.
(c) Corporate Human Rights Benchmark.
(d) World Business Council for Sustainable Development.
(e) Extractive Industries Transparency Initiative.
RESPONSIBLE AND SUSTAINABLE APPROACH Eni Annual Report 2019
6
Letter to shareholders
EMMA MARCEGAGLIA
Chairman
CLAUDIO DESCALZI
Chief Executive Officer
and General Manager
Dear Shareholders,
at the end of our second mandate and at the beginning of a decisive decade for the future of the Oil & Gas industry,
we are proud to deliver you a Company with excellent fundamentals, able to generating returns at the top of the
industry, thanks to a progressively reduced cash neutrality. Looking forward, our Company will by driven by our
decarbonization strategy which will combine the continuing growth of the business in the ever evolving energy
market with an expected significant reduction in our carbon footprint thus actively contributing to the ongoing
decarbonization path of the mankind and supporting the achievement of the goals of the Paris Agreement.
Notwithstanding an unfavorable trading environment affecting the industry from 2014, Eni has grown organically,
while complying with financial discipline. The drivers of this growth have been our successful exploration, where we
were able to maximize value by applying our Dual Exploration Model, and a constant reduction in the time-to-market
of reserves, delivering a winning streak of production records year by year, with an overall increase of 17% from
2014 to the 1.87 million boe/d plateau of 2019.
We have strengthened our business portfolio by diversifying our geographical presence with a better balance along
the value chain thanks to the expansion in the Middle East both in the upstream segment and with the acquisition
of a 20% interest in ADNOC Refining, by growing in Egypt and Indonesia and with the entry in Mexico, by developing
a global LNG business leveraging on the integration of upstream and G&P activities, as well as by enhancing the
production platform in Norway with the Vår Energi transaction and the subsequent acquisition of the ExxonMobil
assets by the JV.
We have restructured the gas and refining businesses through efficiency and optimization actions making them not
only financially self-sufficient, but also able to steadily contribute to the Group's cash flow generation.
This strategy allowed us to halve our cash neutrality and currently our funds from operations are able to cover all
expenses, the capital expenditure and the dividend at a Brent price of 55 $/barrel under the assumptions of the
2019 budget scenario, compared to 114 $/barrel of the 2014 baseline.
This result has been achieved without increasing capital expenditure, but actually reducing them, therefore resulting
in a 16% reduction in net borrowings below €12 billion, after having distributed in the six-year period dividends for
more than €19 billion and having executed the first tranche of Eni’s share buy-back for €0.4 billion.
The traditional Oil & Gas business has substantially accelerated its own decarbonization path by reducing the
emission intensity by 6% per year compared to the 2014 baseline (down by 27% in the period). This result benefitted
from the development of power generation from renewable business, leveraging on the synergies with Eni’s portfolio
of assets, the bio-reconversion of our refineries, the launch of green chemistry and circular economy projects based
on the use of sustainable raw materials and the recycling/reusing of waste (organic and non-organic). Finally we
launched certain forestry initiatives designated at conserving and preserving forests, complementary to the low
carbon strategy.
7
PROFILE OF THE YEAR
The first driver of Eni’s value creation has been the exploration, a distinctive competence of our Company.
In these years, our exploration granted both the replacement of produced reserves with a competitive discovery cost per boe
which is the first step to reduce the break even of upstream projects, and a robust contribution to the cash generation through
the deployment of the Dual Exploration Model.
This strategy foresees the fast monetization of the discovered resources through the dilution of participation interests in
certain mineral interests, while retaining operatorship, otherwise an asset swap as it has been in the case of our entry in the
upstream business in the United Arab Emirates in return for the sale of a 10% stake in the Zohr discovery.
The Dual Exploration Model allowed us to cash in approximately $11 billion. The most recent example is the transaction
finalized at the end of 2019 to divest a 20% interest in the East Sepinggan discovery, offshore Indonesia.
In carrying out exploration activities, Eni has expertly combined initiatives in high-risk/high-reward plays, with near-
field exploration, which targets the discovery of additional mineral potential in mature, proven areas, close to existing
producing platforms, FPSO units and other infrastructures in order to ensure fast support to production and cash flows.
Examples of this approach in 2019 are three discoveries in Egypt and one in Nigeria contextually linked to production,
as well as the resumption of exploration activities in the Block 15/06 in Angola to extend the useful life of the FPSOs in
production that led to a total of five discoveries, identifying 2 billion/barrels of oil in place. The first discovery, Agogo,
started up the production recently.
In these six years we have discovered some 6 billion boe of resources, replacing more than our production, at an average
cost of approximately 1.1 $/boe. In 2019 we discovered 0.8 billion of reserves or resources at near-field prospects (i.e. Egypt,
Algeria, Angola, Nigeria, Ghana and Norway) and in frontier basins (Vietnam and Indonesia).
Our portfolio of mineral interests has been renewed by entering new acreage. In 2019 total acreage amounted to about
360,000 square kilometers, of which 36,000 square kilometers entered in 2019.
The reduction of reserves’ time-to-market is the other great driver for the upstream value creation. Since 2014 the time-to-
market of our projects has been halved to 3.6 years since the discovery and compared to an industry benchmark equal to
the double, leveraging on efficient and original development model based on a fast-track approach, by the parallelization of
different stages of the project and by applying a phased approach which allow to reduce idle capital, as well as by insourcing
critical development phases in order to apply our distinctive industrial competences (such as detailed engineering,
construction supervision and commissioning). In 2019 we have started up six new fields, Area 1 offshore Mexico in just
eleven months from the FID, Berkine North in Algeria, Baltim SW in Egypt, Nasr phase 2 in UAE, Trestakk in Norway and Agogo
in Angola. These start-ups together with the ramp-up of ongoing projects (in particular the Zohr project which reached a
production record at 2.7 bcf/d) contributed approximately 250 kboe/d of new production to the plateau of the year. In addition
to the 2019 start-ups, in the medium term the production growth will be fostered by five FID of the year relating to the Berkine
North phase 2 in Algeria, Balder X in the portfolio of Vår Energi, the gas Dalma structure in the UAE and the upgrading of the
LNG Bonny project in Nigeria.
Our production platform has been strengthened by the expansion in the Middle East, the entry into the upstream of Mexico,
the development of reserves in Egypt at Zohr and the Great Nooros Area, as well as the reorganization of the presence in
Norway thanks to the establishment of the Vår Energi joint venture with local partners, which in its first year of life has
finalized the acquisition of ExxonMobil assets, which make Vår Energi the second largest company in the Norwegian upstream
segment with an expected potential growth of up to 350 kboe/d in 2023.
These initiatives contributed decisively to the better balancing of the geographical distribution of Eni's portfolio, in line
with our strategy.
Our excellent exploration and development phases contributed to reducing the F&D cost which together with opex control
allowed to halve the average break even of Eni’s ongoing development projects at 23 $/bbl, thus making them competitive in
all the decarbonization scenarios.
We replaced with new organic proved reserves 92% of the production (100% when excluding price effects) thanks to new
discoveries and progress in maturing reserves. On an all sources base, the RRR stood at 117%, while the three-year average
organic RRR reached 98%.
Our transformation leveraged also on investments in digital transformation initiatives. In particular, in 2019 we invested about
€100 million in the digital transformation initiatives focused on people safety, asset integrity, efficiency and effectiveness
of internal processes and operations and customer care. Our transformation program almost completed at the Val D’Agri Oil
Center contributed to reduce unplanned shutdowns and operational risks, plant energy consumptions and the relating CO2
emissions from combustion and process.
LETTER TO SHAREHOLDERSEni Annual Report 2019 8
Mid-downstream businesses were deeply restructured and now are financially sustainable in the long-term. Achieved results
are even more considerable, given the structural weaknesses of the wholesale gas scenario, of the refining business and
chemical commodities due to oversupply issues and unabated competitive pressures.
In the G&P business we renegotiated our long-term contracts portfolio aligning it with market conditions and
we optimized logistics, recovering the entire volumes of gas paid and not withdrawn with a financial benefit of
approximately €2 billion. We grew in the LNG business leveraging on the integration with the upstream business,
maximizing the value of equity gas and contributing to the acceleration of FIDs phase at gas reserves development
projects. Today we have reached a portfolio of contracted volumes of 9.5 million tonnes/year, which will progressively
increase in the medium-term in line with the ramp-up/start-up of new equity gas production.
The G&P retail business has become a stable value generator thanks to the selective acquisition of new customers,
credit control, greater efficiency of the organizational and commercial structure, development of innovative extra-
commodity services, as well as a continued growth in the customers portfolio that reached 9.4 million of POD at the end
of 2019. In 2019, in order to increase value for our customers, Eni acquired the subsidiary Evolvere, becoming a leader
in the distributed generation of renewable energy from photovoltaic systems in Italy, in line with Eni's mission, aiming
to create value through the energy transition.
In the R&M segment, proprietary technologies, market opportunities deriving from the energy transition and selective
growth were the drivers of the turnaround. The two structurally non-competitive plants of Venice and Gela have
been converted into modern bio-refineries with a refinery capacity of 1 million tonnes/year (expected to entry full
operations by 2021). These refineries adopt the Ecofining proprietary technology for the production of diesel with a
lower carbon content, with positive effects on the territories. In particular, Gela, started up in August 2019, is designed
to treat advanced and unconventional feedstocks, the latter deriving from food production waste. In 2019 we finalized
the acquisition of a 20% stake in ADNOC Refining for a total consideration of $3.24 billion. It is a high-quality refinery
complex where Eni intends to maximize value by applying proprietary technologies to increase operational flexibility
and energy efficiency. This transaction increases our refinery capacity by 35%, making Eni's portfolio increasingly
integrated along the value chain and even more resilient in a volatile economic scenario.
In the oil marketing activity, capex for the upgrading of our service stations, improvement of customer services,
efficiency and development of the non-oil segment sustained the solid and constantly growing profitability.
In the Chemical business we have progressively reduced the weight of our commodity businesses exposed to the volatility
of the scenario leveraging on technology to enhance the specialties segment, the green and recycled chemical, such as the
Versalis ReVive® products, developed in the Versalis research laboratories.
The heart of our strategies is the Company's aim to become even more sustainable, playing a leading role in achieving
a socially fair energy transition to preserve the environment and ensuring universal access to energy. Eni's
decarbonization path has been accelerated in these six years by leveraging on widespread energy efficiency actions,
the development of the renewable energies business, the launch of circular economy projects and the enter in forestry
conservation initiatives.
In this period, upstream intensity emission reduced by 27%, from approximately 27 tonnes CO2 eq/kboe in 2014 to less
than 20 tonnes CO2 eq/kboe in 2019; the volume of hydrocarbon sent to process flaring decreased by 29% and methane
fugitive emissions by 81% from 2014. Our selected development projects are consistent with our targets on emissions.
The development of energy generation from renewable sources business is based on a model leveraging on industrial,
commercial, logistical and contractual synergies as a result of the integration with the existing assets. In the last two
years, 19 units of energy generation from renewable sources (photovoltaic and wind) have been finalized with an
installed capacity of 190 MW and a wide geographical diversification: Italy, Algeria, Kazakhstan, Australia, Pakistan
and Tunisia. The key factor of our low carbon strategy is the evolution of the Group towards a circular economy
which is based on the sustainability of raw materials (biomass and secondary raw materials), the recycling/reusing
and recovery of raw materials from waste products and the conversion of assets in bio and low carbon ones. The
transformation of Eni in the circular economy starts from the downstream business and proprietary technologies. In
2019 the two major projects of traditional refineries conversion in biorefineries in Venice and Gela, allowed us to reduce
our environmental footprint by lowering harmful emissions compared to the traditional cycle (down by 70% referring
to the Gela plant). In Gela, we started up the pilot plant for the conversion of organic waste into energy products by
applying Eni’s proprietary Waste to Fuel technology. In the Chemical business we are realizing new products and
processes enhancing plastic waste to be transformed into secondary raw materials or new products directly marketed
as for the Versalis Revive® plastic recycled products.
LETTER TO SHAREHOLDERS 9
In 2019 Eni launched certain forestry initiatives designated at conserving and preserving forests, complementary to the
low carbon strategy, which in the long-term will be one of the driver of our low carbon strategy. The first agreement signed in
Zambia with an experienced partner in long-term forest conservation projects, makes Eni an active member in the governance
of Luangwa Community Forests Project, with our commitment to purchase carbon credits in accordance to international
standards, for the next 20 years, until 2038.
The other pillars of Eni’s social and environmental sustainability are the Dual Flag approach and the partnerships value. Eni’s
distinctive driver to manage the business is the value creation for both the Group and the Countries of operation, believing
that long-term relationships and our capacity to access reserves will be strengthened. Examples of our Dual Flag approach are
the gas project in Ghana and the recent MoU signed with the Angolan Government for the development of certain sustainable
initiatives and improvement of quality of life, targeting 180,000 people, including the construction of a 50 MW photovoltaic plant.
In accordance with our decarbonization strategy and our commitment to the UN SDGs, in this period we have promoted
partnerships with private partners and public institutions aiming to share skills, professionalism and relationships making
our initiatives more effective. In particular, we are partners of a number of United Nations agencies: for example in 2019 we
signed a joint declaration with UNIDO (UN agency for industrial development) to support the growth of youth employment, the
agro-food sector and renewable energy in Africa.
MEDIUM/LONG-TERM PLAN
After a period of profound transformation, which has allowed the Group to grow and diversify its activities portfolio, whilst
strengthening its financial structure, Eni is now ready for a new phase of evolution of its business model, strongly oriented
towards creating value over the long-term that combines economic and financial sustainability with environmental
sustainability.
This evolution will be, once again, achieved by leveraging our know-how, proprietary technologies, innovation and the flexibility
and resilience of our assets, which will allow us to seize new opportunities for development and efficiency, as well as further
improve workplace safety.
The founding principles that inspire and guide the Plan's activities and actions are to:
- actively contribute to the achievement of all 17 UN SDGs, which are at the heart of Eni's mission;
- maximize the integration of the portfolio along the entire value chain, from production to end-customers;
- ensure rigorous financial discipline in investment policies and a solid capital structure for the Group to support cash
generation;
- maintain a progressive shareholder remuneration policy.
On the basis of these principles, operational strategies and objectives have been defined for 2035 and 2050, which outline
the evolutionary and integrated path of the individual businesses. The speed of evolution and the relative contribution of each
business will depend on market trends, technological developments and legislation.
The Eni of the future will therefore be even more sustainable. It will reinforce its role as a global player in the world of energy
with renewables and circular economy activities. These nascent businesses will develop strongly and be highly connected
to our existing businesses. The production of oil and gas is expected to reach a plateau in 2025 and to decline in the following
years mainly for the oil component. The result will be a portfolio that is more balanced and integrated and will be stronger for
its adaptability and competitive shareholder remuneration.
The evolution of the business portfolio will have a significant impact on the reduction of the carbon footprint, whose targets
are set as of now. We have been the first company giving itself a comprehensive calculation methodology for emissions that
includes direct and indirect emissions deriving from the end use of the products, regardless of whether they are produced by
us or purchased from third parties. Consequently, targets set for the reduction of our absolute GHG emissions do not have a
quantification directly comparable with other methodologies, due to the extent of the detection.
In particular, Eni will pursue a strategy that aims to:
- obtain by 2050 an 80% reduction in scope 1, 2 and 3 net emissions, with reference to the entire life-cycle of the energy
products sold (well beyond the 70% threshold defined by the IEA in the SDS scenario in line with the objectives of the Paris
Agreement) and a 55% reduction in emission intensity compared to 2018;
- reinforce its role as a global player in the energy market, leveraging on an increasingly balanced and integrated portfolio of
activities;
- optimize the flexibility of its business portfolio, so as to respond to external market factors and to position the Company to
seize opportunities;
- generate value for its shareholders by maintaining the current progressive remuneration policy.
LETTER TO SHAREHOLDERSEni Annual Report 2019 10
The following decarbonization targets confirm and build on previously announced ones:
- net-zero carbon footprint by 2030 for scope 1 and 2 emissions from upstream activities;
- net-zero carbon footprint for scope 1 and 2 emissions from the Eni Group by 2040.
ACTION PLAN 2020-2023
Given the uncertainties relating to the macroeconomic and political outlook and the complexity of the interaction
between measures to combat climate change and energy demand, we maintain a prudent financial approach in
investment decisions. The four-year investment plan, focused on high-value projects with short pay-back period,
provides for investments of around €32 billion in 2023 and is characterized by a high level of flexibility with around 60%
of investments uncommitted in 2022-2023.
Eni's investment program has been designed to achieve high-returns and resiliency even in a challenging scenario.
In particular, the current portfolio of upstream projects in execution has a break-even price of 23 $/bbl (25 $/bbl in
the previous plan) and an overall IRR of approximately 25%. These projects remain competitive even in a low carbon
scenario. Adopting the IEA SDS scenario, which foresees a huge increase in the costs of emitting CO2 on a global scale,
the overall IRR would be reduced by 0.7 percentage points.
In the E&P segment we plan to maximize cash generation leveraging on organic growth, exploration successes and
efficiency in development activity and operations. Eni expects a strong cash generation growth with a cumulative
organic free cash flow in 2020-2023 of over €25 billion.
The development of our pipeline of Oil & Gas projects will drive a production growth of 3.5% on average in the period
2019-2023 targeting a plateau of 2.2 million boe/d. Continuing production ramp-ups at existing fields and planned
start-ups will contribute about 800 kboe/d at 2023. Production start-ups are well geographically diversified and refer
to the development of the 15/06 hub in Angola, the start-up of the cluster of discoveries of Area 1, in Mexico, following
the early production phase in 2019, the projects in the portfolio of Vår Energi in Norway (Balder X, Johan Castberg and
Breidablikk), the production start-up of Coral in Mozambique, Merakes in Indonesia and Nenè phase 2B in Congo as well
as the gas structures of Dalma in the UAE.
We have a high visibility on these projects being the greater portion of them already in the development phase. The
FID is expected to be made in 2020 for the remaining projects planned to be started in the next four years. Planned
investments to promote reserves and production optimization amount to €21 billion. Finally, we plan fourteen relevant
FIDs that will ensure flexibility and growth options beyond the plan horizon.
The strategic guidelines of exploration activity are to retain financial discipline in spending and to balance initiatives
in near-field/proven areas and high-risk/high-reward frontier exploration plays, which will be implemented on the basis
of operatorship and high working interest according to the possible application of the Dual Exploration Model in case
of success. The activities will be selected so as to guarantee geographical diversification and will target the promising
basins in the Middle East, Mexico, Norway and the Far East. The goal is to discover 2.5 billion boe at a competitive unit
cost of 1.5 $/boe.
The operations will be conducted by focusing on the continuous development and implementation of new technologies
for improving drilling performance and reducing blow out risks, on asset integrity and on energy efficiency.
In the G&P segment, value creation in the wholesale gas business will be driven by the de-risking of the wholesale gas
and power portfolio and by LNG growth.
The strategic guidelines are the continuing renegotiation of contracts to align gas prices to the market and obtain higher
contractual flexibility, optimization of sunk logistic costs and the exploitation/development of the assets and of the portfolio's
flexibilities to increase margins. In the LNG business, we intend to grow by building upon the synergic integration with
upstream to enhance value of equity reserves and to enter new markets, by targeting a contracted portfolio of 16 MTPA by
2025, of which approximately 70% from equity production, in particular Mozambique, Egypt and Nigeria.
We intend to maximize the value of our G&P retail business through selective growth in the domestic market,
continuing improvement of operating efficiency and customer experience, management of the credit risk and focus on
non-commodity services leveraging the increasing demand of energy efficiency and distributed generation. We expect
to grow our retail customers portfolio to approximately 11 million POD by 2023, an increase of 15% from 2019.
We expect a strong increase in R&M profitability, assuming no changes in the scenario, driven by selective growth
initiatives and a continued focus on efficiency, as well as by synergies with the path of decarbonization and transition
to the circular economy. The ADNOC Refining expansion plan agreed with the other venture partners will allow us to
maximize the return on the investment by leveraging Eni's technology to upgrade the refinery's operational flexibility
with reduced cost of feedstock, improvement in energy efficiency and targeted increases in capacity.
LETTER TO SHAREHOLDERS 11
The European refining system will be consolidated by restarting the EST plant at the Sannazzaro refinery and other
optimizations.
The green processing capacity will target 1 million tonnes/year (by 2021) thanks to the Gela ramp-up and upgrades
at the Venice plant, while the mix of green feedstocks will be progressively changed with advanced and second
generation feedstocks leveraging Eni's circular initiatives, aiming at cutting to zero use of palm oil feedstock by 2023.
In the marketing activity we forecast stable and robust results thanks to actions to preserve volumes sold, in particular
in high margin segments, investments in modernization and improvement of efficiency, the evolution of our stations to
a service station, as well as the development of smart mobility services and the sale of alternative fuels.
The industrial plan of Versalis is focused on the strategic repositioning of the business. This will be driven by the
enhancement of the traditional assets to increase their resilience to the scenario, the shift in the production mix towards
greater added value specialties and the acceleration of the green transformation and to circular economy. In this latter
area, the Matrica production platform will be optimized, being able to obtain high-value applications for the electronic,
cosmetic and bio-herbicide industries, as well as we are planning the start-up of bioethanol production from biomass and
the development of circular initiatives for the production of recycled plastics (mechanical and chemical processes).
The short-term decarbonization strategy will progress along the defined guidelines: continuous improvement of energy
efficiency in operations, increase the share of gas production on total hydrocarbons, development of renewable
sources production capacity, transformation into circular economy of downstream businesses and ramp-up of forestry
initiatives. The first milestone of this path, with a necessarily long-term perspective, is the achievement of the net
carbon neutrality of the upstream business in relation to equity production volumes by 2030.
In the medium-term we foresee the achievement of zero flaring in 2023, a further reduction in the upstream emission
intensity by 38% from 2014, the development of renewable energy projects targeting an installed capacity of 3 GW in
2023, ramping up to 5 GW in 2025, leveraging strategic partnerships, such as the one with Cassa Depositi e Prestiti in
Italy, as well as the development of mixed decarbonization/circular economy projects relating to bio-refineries supplied
exclusively with 2nd generation feedstocks, the development of the production of recycled plastics and bioethanol,
as well as the start up by 2025 of Waste to Fuel units for the treatment of the organic fraction of urban waste
produced by six million equivalent inhabitants in Italy with the public-private partnership formula. The development of
decarbonization initiatives and circular economy projects will be supported by a capex plan of €4 billion, 65% of which
for the increase of renewable generation capacity.
Conclusively, the plan's initiatives aiming at maximizing the value of our asset portfolio will allow Eni to further reduce
the cash neutrality and to strengthen the Company's environmental sustainability in line with the UN SDGs.
We wish to thank all of the women and men of the Eni team, for the quality and steadiness of the efforts made in these
years. Without their contribution, the Company would not have been able to achieve the results that make us proud of.
On the basis of 2019 results, we are going to propose the payment of a full dividend of €0.86 per share for fiscal
year 2019, of which €0.43 per share already paid as interim dividend in September 2019 , at the Annual General
Shareholders' Meeting convened on May 13, 2020.
Considering the actions envisaged in the plan period, Eni is reaffirming its progressive shareholder remuneration policy
and for 2020 is projecting a dividend of €0.89 per share, growing by 3.5%, and a share buyback program of €400 million.
February 27, 2020
In representation of the Board of Directors
Emma Marcegaglia
Chairman
Claudio Descalzi
Chief Executive Officer and General Manager
LETTER TO SHAREHOLDERSEni Annual Report 2019 12
Eni at a glance
€8.60 BLN
down by 24% vs. 2018
GROUP ADJUSTED OPERATING
PROFIT
€12.1 BLN
down by 4% vs. 2018
following a worsening
scenario
ADJUSTED NET CASH FLOW
FROM OPERATIONS
55 $/barrel
2019 CASH NEUTRALITY
AT BUDGET SCENARIO
0.34 TRIR
DOWN BY 3%
VS. 2018
In 2019, Eni achieved excellent results, enhancing the business portfolio through geographical
diversification thanks to the expansion in the Middle East both in the upstream segment and through
the purchase of the 20% share in ADNOC Refining, the growth in Egypt and Indonesia, the global
development of the LNG business, as well as the upgrading of the production platform in Norway with
the Vår Energi transaction and the subsequent purchase of the ExxonMobil assets by the JV.
The strategic repositioning of R&M and Versalis in the green business and the circular economy
has been set with the start-up of the Gela bio-refinery and the launch of a new line of polymers
from mechanical recycling of used plastics.
The traditional Oil & Gas business is now more solid also thanks to the acceleration of the
decarbonization path with the reduction of the upstream GHG emission intensity at a 6% rate per year
from the 2014 baseline (down by a cumulative 26% in the period), the development of the business
of power generation from renewable sources in synergy with asset portfolio, the bio-conversion
of refineries, the launch of green chemistry and circular economy projects based on the use of
sustainable raw materials, the recycling/reuse of waste (organic and non-organic) and, finally, with
the launch of the forestry conservation initiatives, complementary to the low carbon strategy.
These positive results were reported in a challenging operating and trading environment, due to
the slowdown in global macroeconomic cycle, the reduction in international trade, as well as the
adverse geopolitical developments.
All these factors negatively affected the demand of commodities and the global consumption
of fuels and plastic feedstocks, boosting the negative impact of the oil and gas oversupply
in the upstream, the competitive pressure from producers with lower cost structure and the
overcapacity in the refining and chemical sector.
BRENT DATED ($/barrel)
64.30
2019
71.04
2018
54.27
2017
SERM ($/barrel)
2019
2018
2017
4.3
3.7
5.0
AVERAGE EUR/USD
EXCHANGE RATE
2019
2018
2017
1.119
1.181
1.130
PSV vs. TTF (€/kmc)
2019
2018
2017
29
17
28
Despite the unfavorable scenario and cash constraints, Eni combined growth and financial
discipline, leveraging on successful exploration and lower of reserve's time-to-market. Growth
and efficency actions and reduced capex allowed to reach a cash neutrality, at a Brent price of
55 $/barrel at 2019 budget scenario, covering expenses, capex and dividends with the cash flow
from operations.
Confirmed the Group's financial strength with net borrowings at €11.48 billion (before
IFRS 16) financing the 20% acquisition of ADNOC Refining amounting to $3.2 billion, paying
dividends in the year for overall €3 billion and executing the first tranche of the buy-back
program (€0.4 billion).
PRODUCTION VS. CAPEX
(mmboe/d)
1.90
1.80
1.70
1.60
ENI'S SHAREHOLDERS RETURN (€ bln)
4.4
3.5
2.9
2.9
3.0
3.4*
€20 billion in the last 6 years
(€ bln)
14
10
6
2
2014
2015
2016
2017
2018
2019
2014
2015
2016
2017
2018
2019
hydrocarbon production (mmboe/d)
(*) including €400 million relating to 2019 buy back
capex (€ bln)
1313
ENI GROUP
Operating profit (loss)
(€ million)
2019 2018 2017
6,432 9,983 8,012
Adjusted operating profit (loss)
(€ million)
8,597 11,240 5,803
Net cash flow from
operating activities
(€ million)
12,392 13,647 10,117
TRIR (Total Recordable Injury Rate)
(total recordable injuries/worked hours) x 1,000,000 0.34
0.35
0.33
Leverage before IFRS 16
0.24
0.16
0.23
EXPLORATION & PRODUCTION 2019 2018 2017
Adjusted operating profit (loss)
(€ million)
8,640 10,850 5,173
Hydrocarbon production
(kboe/d)
1,871 1,851 1,816
Opex per boe
($/boe)
Profit per boe
($/boe)
GHG emissions/100% operated
hydrocarbon gross production
(tonnes CO2 eq/kboe)
6.4
6.8
6.6
5.1
9.3
8.7
19.58 21.44 22.75
GAS & POWER
2019 2018 2017
Adjusted operating profit (loss)
(€ million)
654
543
214
Worldwide gas sales
(bcm)
LNG sales
(bcm)
73.07 76.71 80.83
10.1
10.3
8.3
GHG emissions/Equivalent produced
electricity (Eni Power)
(gCO2 eq/kWheq)
Retail customers in Italy
(million)
394
402
395
7.74
7.74
7.65
down by 9%
vs. 2018
UPSTREAM GHG EMISSION
INTENSITY
1.87 MLN boe/d
RECORD IN HYDROCARBON
PRODUCTION
REFINING & MARKETING
AND CHEMICALS
Adjusted operating profit (loss)
(€ million)
2019 2018 2017
(48)
380
991
7.3 BLN boe
HYDROCARBON
PROVED RESERVES
117%
ALL SOURCES
REPLACEMENT RATIO
Retail sales of petroleum products in Europe
(mmtonnes)
8.25
8.39
8.54
Refinery throughputs on own account
(mmtonnes)
22.74 23.23 24.02
3.5 $/barrel
BREAKEVEN REFINING
MARGIN AT BUDGET
SCENARIO
€0.65 BLN
G&P ADJUSTED
OPERATING PROFIT
GHG emissions/Refinery throughputs
(raw and semi-finished materials)
(tonnes CO2eq/ktonnes)
248
253
258
Sales of petrochemical products
(ktonnes)
4,285
4,938 4,646
ENI IN SINTESIEni Relazione Finanziaria Annuale 2019
14
Stakeholders
engagement activities
The relationship with its stakeholders, listening and sharing decisions with people in the countries where it operates are
fundamental elements for Eni: knowledge of their point of view and their expectations are the foundation of its commitment
to building transparent and lasting relationships based on mutual trust. Eni has operations in 66 countries with very different
social, economic and cultural contexts and it believes that dialogue and the direct involvement of stakeholders, are fundamental
elements for creating value in the long term, in every phase of its business activities.
Topics arisen from the dialogue with stakeholders
PU
Relations with the community and local development
Climate change and energy efficiency
Integrity and transparency
Challenges for development
Management of environmental impacts
Health and safety in the workplace
Corporate Governance
Economic and financial value creation
Fairness and transparency of commercial policies
Protection of Human Rights
Sustainable management of the supply chain
Labour standards & diversity
Asset integrity and emergency management
Response capacity to the consumers needs
Risks and vulnerabilities in the energy sector
Organizational environment, welfare and parenthood
Digitalization, technological innovation and research
Circular economy
CD
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F I N
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LOCAL
COMMUNITIES
& COMMUNITY
BASED
ORGANIZATIONS
SP
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PA
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PLIE
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15
In order to engage in this daily and proactive dialogue with multiple stakeholders at local, national and international level, since 2018, Eni
has been using an IT platform called Stakeholder Management System (SMS), which supports the management of its complex network of
relationships. The system is in use in 37 countries and tracks over 3,500 stakeholders. The SMS allows to record and view relationships
with each stakeholder category, highlighting any critical issues and areas for improvement, the main issues of interest, the potential
impacts on Human Rights, also identifying the possible presence of vulnerable groups and areas listed by UNESCO as sites of cultural
and/or naturalistic interest (WHS - World Heritage Sites) in the countries where it operates.
Main stakeholder engagement activities during the year
PU
ENI’s PEOPLE AND NATIONAL
AND INTERNATIONAL TRADE
UNIONS
FC
FINANCIAL
COMMUNITY
LC
LOCAL COMMUNITIES
AND COMMUNITY BASED
ORGANIZATIONS
˛ Professional and training paths on emerging skills
related to business strategies and expansion of
skills mapping
˛ Training initiatives to support inclusion and
recognition of the value of all kinds of diversity and
international initiatives supporting team building
and innovation (Hackathon)
˛ Presentation of the 2019-22 strategic plan,
followed by Road-Show of the CEO and top
management at the main stock exchanges
˛ Eni's President Governance Road Show
˛ Dialogue with the market, in particular on the
2019 remuneration policy, in view of the 2019
Shareholders' Meeting
˛ Involvement of about 650 communities
(including indigenous ones) close to plants
˛ Consultation of local authorities and communities
for new exploration activities and/or the
development of new projects as well as for the
planning, management and improvement of
social projects(a)
˛ Fourth edition of the climate analysis
˛ Initiatives for parenthood (smart working and
school nursery) and family members with
disabilities
˛ Meeting with national and international trade unions
(renewal of the Global Framework Agreement) to
discuss the different social and trade union realities
of the Countries where it operates
SP
SUPPLIERS
AND COMMERCIAL
PARTNERS
˛ Supplier involvement with Human Rights
Assessment
˛ Communication, feedback and improvement plans
˛ Participation in IPIECA WG: Forum on O&G
Sustainability best practices
˛ Green Sourcing Project: identification of supply
chain levers to reduce environmental impacts
˛ Discussion of human rights clauses in upstream
joint venture contracts
˛ Meeting in Abu-Dhabi for investors and financial
analysts on the expansion strategy in the Arabian
Peninsula
˛ Mapping of community relations, requests and
grievances and definition of local engagement
content
˛ Meetings on quarterly results
˛ Participation of top management in thematic
conferences organized by banks
CC
CUSTOMERS
AND CONSUMERS
NI
NATIONAL, EUROPEAN
AND INTERNATIONAL
INSTITUTIONS
˛ Meetings and workshops with Presidents,
Secretaries General and Energy Managers
of national and local CA(b) on issues such as
sustainability, circular economy, reclamation
and environmental remediation
˛ Sponsorship of CA initiatives on sustainability
and circular economy
˛ Territorial meetings with the regional CA of the
Italian National Council of Consumers and Users
˛ Survey of national and regional CA representatives
on circular economy, sustainability and energy
transition
˛ Dialogue with the CIDU(c) and the National Contact
Point (Italy) for OECD Guidelines
˛ Meetings with Italian political representatives and
institutions, both central and local, on energy,
climate and environmental issues, circular
economy and sustainable development
˛ Active participation in institutional technical round
tables, joint committees, WGs and other meetings
promoted by Italian Government and Parliament
˛ Visits by Italian institution delegations, central and
local, to Eni industrial plants, sites and research
centres
UR
UNIVERSITIES AND
RESEARCH CENTRES
OA
VOLUNTEER ORGANIZATIONS
AND CATEGORY ASSOCIATIONS
CD
ORGANIZATIONS FOR
COOPERATION AND
DEVELOPMENT
˛ Meetings with Universities, Research Centres and
third-party companies with which Eni collaborates
or interfaces in the development of innovative
technologies
˛ Agreements and collaborations with the
Polytechnic of Milan and Turin, the Universities of
Bologna, Naples and Pavia, MIT, CNR, INSTM, ENEA
and INGV(d)
˛ Establishment with the CNR of 4 research centres
in Southern Italy for sustainable environmental
and economic development in Italy and worldwide
˛ Collaboration with the Polytechnics of Milan in the
organization of the Master's in Energy Innovation
and for the development of Impact Assessment
Models (the latter also with the University of Milan
- Faculty of Agrarian Sciences)
˛ Membership and participation in OGCI, IPIECA,
˛ Development of new public-private partnership
WBCSD, UN GLOBAL COMPACT, EITI(e)
˛ Collaboration with IHRB(f) and other international
human rights institutions
˛ Conferences, debates, seminars and training
initiatives on sustainability issues (energy,
circular economy, remediation, corporate social
responsibility); implementation of guidelines and
sharing of best practices
˛ Participation in meetings of the association
bodies and working tables on strategic issues,
monitoring legislative developments
˛ Meetings with Local Business Associations on the
supplier qualification process
models
˛ Dialogue and development of collaborations with
United Nations organizations and cooperation
agencies (UNIDO; UNESCO; FAO(g); Halo Trust
Foundation)
˛ Consolidated relations with Faith-Based
Organizations (2nd “Vatican Dialogue on Energy
Transition and Care for Our Common Home”;
Scientific and Organizational Committee of the
Mediterranean Frontier of Peace event organized
by the Italian Episcopal Conference)
(a) Angola – economic diversification, Iraq – education, Pakistan – access to water,
Mozambique - access to energy, Italy/Basilicata - CASF (Agricultural Centre for
Experimentation and Training).
(b) Consumers' Association.
(c) Inter-Ministerial Committee on Human Rights.
(d) Massachusetts Institute of Technology; Italian National Research Institute; Italian
National Inter-University Consortium for Materials Science and Technology; Italian National
Agency for New Technologies, Energy and Sustainable Economic Development; Italian
National Institute of Geophysics and Volcanology.
(e) Oil and Gas Climate Initiative; World Business Council for Sustainable Development; Italian
Inter-Ministerial Human Rights Committee; Extractive Industries Transparency Initiative.
(f) Institute for Human Rights and Business.
(g) United Nations Industrial Development Organization; United Nations Educational, Scientific
and Cultural Organization; Food and Agriculture Organization.
STAKEHOLDERS ENGAGEMENT ACTIVITIESEni Annual Report 2019 16
Strategy
Industrial plan
After a period of profound transformation, which has allowed the Group to grow and diversify its portfolio, whilst strengthening its financial
structure, Eni is now ready for a new phase of evolution of its business model, strongly oriented towards creating value over the long-term that
combines economic and financial sustainability with environmental sustainability.
This evolution will, once again, be achieved by leveraging our know-how, proprietary technologies, innovation and the flexibility and resilience
of our assets, which will allow us to seize new opportunities for development and efficiency, as well as further improve workplace safety.
The founding principles that inspire and guide the Plan's activities and actions are to:
˛ actively contribute to the achievement of all 17 UN SDGs, which are at the heart of Eni's mission;
˛ maximize the integration of the portfolio along the entire value chain, from production to end-customers;
˛ ensure rigorous financial discipline in investment policies and a solid capital structure for the group to support cash generation;
˛ maintain a progressive shareholder remuneration policy.
On the basis of these principles, operational strategies and objectives have been defined for 2035 and 2050, which outline the evolutionary
and integrated path of the individual businesses. The speed of evolution and the relative contribution of each business will depend on market
trends, technological developments and legislation.
The evolution of the business portfolio enables Eni to reach the objectives of reducing its carbon footprint, which are considered fixed.
In particular, Eni will pursue a strategy that aims to:
˛ obtain by 2050 an 80% reduction in net scope 1, 2 and 3 emissions, with reference to the entire life-cycle of the energy products sold and a
55% reduction in emission intensity compared to 2018;
˛ reinforce its role as a global player in the energy market, leveraging an increasingly balanced and integrated portfolio of activities;
˛ optimise the flexibility of its business portfolio, so as to respond to external market factors and position the Company to seize
opportunities;
˛ generate value for its shareholders by maintaining the current progressive remuneration policy.
The following decarbonisation targets confirm and build on previously announced ones:
˛ net-zero carbon footprint by 2030 for scope 1 and 2 emissions from upstream activities;
˛ net-zero carbon footprint for scope 1 and 2 emissions from the Eni group by 2040.
The Action plan 2020-2023 declines and defines the first steps of Eni’s evolution path aiming at value creation through organic and sustainable
growth of its activities, consistently with the medium-long term strategies.
The growth will leverage an operating model characterised by the constant commitment to minimizing risks and the centrality of human
capital, the environment and safety.
STRATEGY 1717
The balanced development of the portfolio of activities will allow a progressive remuneration of the shareholders to guarantee a solid financial
structure.
Eni, continuing its tradition and in line with the United Nations SDGs, will continue to promote local development by leveraging its cooperation
model (dual flag approach) and public-private partnerships.
The development will be reached promoting access to electricity and water but also by developing projects for health, education and hygiene as
well as sharing its know-how.
Upstream
The principal strategic guidelines in the medium/long-term are to:
˛ maintain a resilient portfolio of conventional assets that is characterised by: low breakeven, accelerated time to market and limited
exposure beyond the medium term;
˛ enhance portfolio flexibility with a confirmed 3.5% production CAGR to 2025, at which point production will plateau followed by a
flexible decreasing trend mainly in oil production. The gas share of production is expected to reach 60% by 2030 and around 85% in
2050;
˛ confirm the previously announced GHG reduction targets.
In line with the medium/long-term strategy, the 2020-2023 action plan has the following objectives:
˛ An enhanced exploration portfolio that targets the discovery of 2.5 bln boe contributing to geographical diversification by leveraging:
• operatorship and high working interest in exploration permits in order to take advantage of the "dual exploration model" to monetize
discoveries quickly;
• exploration focus on near-field and proven basins;
• selected initiatives on frontier basins;
˛ Cash generation growth with a cumulative organic free cash flow in 2020-2023 of over €25 billion. This objective will be achieved with:
• production growth at an average annual rate of 3.5% in the period 2019-2023 thanks to the contribution of projects already started
or that will start up in the four-year plan;
• further development of initiatives integrated with Gas & Power for enhancing the value of equity gas;
• stronger project development model based on phasing and design-to-cost in order to reduce the execution risk and financial
exposure;
• efficiency and operational continuity optimization.
˛ Digital transformation to further improve workplace safety and asset integrity.
STRATEGYEni Annual Report 2019 18
Gas & Power
The main medium/long-term strategic guidelines have the following objectives:
˛ expansion of retail activities to a customer base of over 20 million by 2050;
˛ business growth in combination with the expansion of renewables and bio-methane;
˛ complete transition to bio and renewable products by 2050;
˛ enhanced offer to customers with supply of new generation services;
˛ Midstream Gas & Power market access role strengthened to include all non-oil commodities;
˛ Midstream Gas & Power activities focused on marketing of equity products: natural gas, bio-methane, blue energy and hydrogen;
˛ Midstream Gas & Power confirmed to manage CCGT power plants, integrated with CO2 capture and storage capacity.
In line with the medium-long term strategy, the 2020-2023 Action Plan has the following objectives:
˛ expected growth in retail customers to approximately 11 million by 2023, of which over 4 million in power;
˛ development of new products and focus on non-commodity services;
˛ continuation of restructuring of gas supply portfolio and reduction of logistics costs, through optimization actions and contract
renegotiation;
˛ growth of LNG portfolio through development of new markets and integration with upstream to enhance value of equity gas. Portfolio of
expected contracted LNG volumes to reach 16 MTPA by 2025;
˛ maximize Power activity results thanks to the flexibility and efficiency of power generation plants.
These actions will generate a cumulative organic free cash flow equal to €2.1 billion in the period 2020-2023.
Refining & Marketing
The main medium/long-term strategic guidelines are as follows:
˛ expansion of bio-refining capacity to over 5 million tonnes per year, supplied exclusively with 2nd and 3rd generation "palm-oil free" feedstocks,
in target areas such as the Far and Middle East, Europe for bio-jet fuel production and the United States;
˛ progressive conversion of traditional Italian refining sites through new plants for production of hydrogen, methanol, biomethane and products
from recycling of waste materials;
˛ in the long-term, the Ruwais refinery in the United Arab Emirates will be the only traditional refinery in operation, capitalising on its optimal
location and operational efficiency;
˛ gradual evolution of product mix sold in retail outlets, reaching 100% decarbonised products by 2050;
˛ increase of additional services offer to improve margins and enhance customer loyalty.
In line with the medium/long-term strategy, the 2020-2023 Action Plan has the following objectives:
˛ consolidation and integration of traditional refining activities with Ruwais refinery reaching full potential including contribution from trading
activities;
˛ continued diversification through investments in biorefining. Our bioprocessing capacity will be 1 million tonnes by 2023 and palm-oil free;
˛ development of circular economy initiatives for the production of hydrogen and methanol from the recycling of waste materials and from castor
oil, both new feedstocks for biorefining;
˛ European marketing consolidation favouring high-margin segments and further development of non-oil services in retail;
˛ increased offer of alternative fuels and development of sustainable mobility.
These actions will make it possible to achieve a cumulative organic free cash flow of € 2.6 billion over the period 2020-2023.
Chemicals
The main medium/long-term strategic guidelines are as follows:
˛ specialization in the production of high-quality and high-performance polymers;
˛ development and integration of chemistry from renewables and chemical and mechanical recycling;
˛ transformation via pyrolysis of non-recyclable plastics into polymers with identical characteristics to those produced by hydrocarbons;
˛ establishment of integrated platform to maximize synergies with refining in gasification processes involving all types of plasmix.
STRATEGY 19
In line with the medium-long term strategy, the 2020-2023 Action Plan has the following objectives:
˛ rebalance the ethylene-polyethylene chain integrated with mechanical and chemical recycling and the recovery of cracking efficiency;
˛ gradual shift of polymers portfolio towards products with greater added value and extension of downstream chain towards compounding to
reduce margin volatility;
˛ development of chemicals from renewables through new processes and products;
˛ progressive reduction of GHG emissions, increasing energy efficiency and feedstock flexibility;
˛ international growth in synergy with Eni’s other businesses.
These actions will allow for a cumulative organic operating cash flow of €0.4 billion.
Shareholders remuneration
Eni confirms its commitment to a progressive remuneration policy linked to underlying earnings and free cash flow growth. In light of
the achieved performance, the expected growth in all businesses and the solid financial structure, Eni intends to increase the 2020
cash dividend by 3.5% to €0.89 per share and to continue to buy-back program for an overall amount of €400 million in 2020.
Focus on decarbonization
Eni's strategy is critical in driving a reduction in the Group's carbon footprint.
Eni has developed a rigorous methodology for the comprehensive measurement of GHG emissions. This method considers scope 1, 2 and
3 emissions, both in absolute and relative terms, related to energy products sold, whether derived from our own or purchased production.
This distinctive approach is more comprehensive than current emissions standards and provides an integrated view of emissions.
The results of the industrial strategy lead to a reduction of 80% in absolute emissions by 2050 (well above the 70% threshold indicated
by the IEA in their SDS scenario compatible with the targets set by the Paris Agreement) and a reduction of 55% in emissions intensity.
The methodology was reviewed, independently, by experts from Imperial College London (via Imperial Consultants) whilst the
results of its application were verified by the independent certification company RINA.
The actions underway will contribute to achieving the following results:
˛ progressive reduction of hydrocarbons production, with rising proportion of gas to oil;
˛ focus on gas equity marketing combined with projects for the capture and storage of CO2 and the progressive reduction of non-equity gas sales;
˛ conversion of European refineries into plants for the production of hydrogen and for the recycling of waste materials;
˛ primary and secondary forest conservation projects to offset CO2 emissions exceeding 30 million tons per year by 2050;
˛ projects to capture CO2 of over 10 million tons per year by 2050, with a first project under study for the Ravenna hub in Italy,
where it will be possible to capture CO2 from neighbouring industrial sites and gas-powered electricity generation;
˛ renewables installed capacity exceeding 55 GW by 2050;
˛ growth of retail clients to over 20 million by 2050.
Eni also confirms its upstream net carbon neutrality target for scope 1 and 2 emissions by 2030 and announces a new net carbon
neutrality for scope 1 and 2 emissions for the entire Eni group by 2040.
FOCUS ON RENEWABLES
The main medium/long-term strategic guidelines have the following objectives:
˛ progressive expansion of installed global capacity to over 55GW by 2050;
˛ expansion to new areas based on where we have an existing or targeted customer base in order to maximize value from an
integrated model;
˛ further development in areas where Eni already operates.
In line with the medium/long-term strategies, the 2020-23 Action Plan provides for:
˛ installed capacity of 3GW by 2023 and 5GW by 2025;
˛ investments of €2.6 billion over the plan period.
STRATEGYEni Annual Report 2019 20
Integrated Risk Management
The integrated risk management (IRM) model is aimed at ensuring that management
takes risk-informed decisions, with adequate consideration of actual and prospective
risks, including medium and long-term ones, within the framework of an organic
and comprehensive vision.
The IRM Model is based on a system of methodologies and skills that leverages
on principle of the third parties assessments (data quality, objectivity of the detection
and quantification of the mitigation actions) in order to improve the effectiveness
of the analyses, ensure an adequate support for the main decision making processes
(definition of the Strategic Plan and medium and long-term objectives) and guarantee
the disclosure to the administration and control structures.
Through the inclusion of industrial risk assessment activities as well as analysis
and operational management of contractual risks, the support for decision-making
processes has been strengthened by improving awareness of the risk profile,
also with a view to the full life cycle of the business activities.
Integrated Risk Management Model
The IRM Model is characterized by a structured approach, based on
international best practices and considering the guidelines of the
Internal Control and Risk Management System (see page 29), that
is structured on three control levels. Risk Governance attributes
a central role to the Board of Directors (BoD) which defines the
nature and level of risk in line with the strategic targets, including
in evaluation process all those risks that could be consistent for
the sustainability of the business in the medium-long term. The
BoD, with the support of the Control and Risk Committee, outlines
the guidelines for risk management, so as to ensure that the main
corporate risks are properly identified and adequately assessed,
managed and monitored, determining the degree of compatibility
with company management consistent with the strategic targets.
For this purpose, Eni’s CEO, in particular, through the IRM process,
presents every three months a review of the Eni’s main risks to
the Board of Directors. The analysis is based on the scope of the
work and risks specific of each business area and processes
aiming at defining an integrated risk management policy; the CEO
also ensures the evolution of the IRM process consistently with
business dynamics and the regulatory environment. Furthermore,
the Risk Committee, chaired by the CEO, holds the role of consulting
body for the latter with regards to major risks. For this purpose, the
Risk Committee evaluates and expresses opinions, at the instance
of CEO, related to the main results of the IRM process.
INTEGRATED RISK MANAGEMENT MODEL
BOARD OF DIRECTORS
CONTROL AND RISK COMMITEE/BOARD OF AUDITORS
CHAIRMAN
CEO
RISK COMMITEE
COMPLIANCE COMMITEE
Integrated Risk Management
Integrated Compliance
1st line
“Line” managers - risk owners
2nd line
Risk and Control functions*
3rd line
Internal Audit
(*) Including Integrated Risk Management function.
21
Integrated Risk Management Process
The IRM process ensures the detection, consolidation and analysis
of all Eni’s risks and supports the BoD to verify the compatibility of
the risk profile with the strategic targets, also in a medium-long term
approach. The IRM supports management in the decision-making
process by strengthening awareness of the risk profile and the
associated mitigations. The process, regulated by the "Management
System Guideline (MSG) Integrated Risk Management" is continuous,
dynamic and includes the following sub-processes: (i) risk governance,
methodologies and instruments, (ii) risk strategy, (iii) integrated risk
management, (iv) risk knowledge, training and communication.
The IRM process starts from the contribution to the definition of
medium and long-term plans and Eni's Strategic Plan (risk strategy)
through the identification of proposals for de-risking objectives and
strategic treatment actions, as well as the analysis of the risk profile
and business opportunities underlying the plan and the long-term
development. The Integrated Risk Management sub-process includes:
periodic risk assessment and monitoring cycles (Integrated Risk
Assessment) in order to understand the risks taken on the basis of the
strategic and medium-long term targets and the initiatives defined to
achieve them; analysis and management of contractual risks (Contract
Risk Management) aimed at the best allocation of the contractual
responsibilities with the supplier and their adequate management in the
operational phase; integrated analysis of existing risks in the Countries
of presence or potential interest (Integrated Country Risk - ICR) which
represents a reference for risk strategy, risk assessment and project
risk analysis activities; support to the decision-making process for the
authorization of investment projects and main transactions (Integrated
Project Risk Management & M&A).
The risks are assessed with quantitative and qualitative tools
considering both the likelihood of occurrence and the impacts that
would occur in a defined time horizon when the risk occurs.
The assessment is expressed following an inherent and a residual
level (taking into account the effectiveness of the mitigation actions)
and allows to measure the impact with respect to the achievement of
the objectives of the Strategic Plan and for the whole life as regards
business projects. The risks are represented on the basis of the
likelihood of occurrence and the impact on matrices that allow their
comparison and classification by relevance. In 2019, two assessment
sessions were performed: the Annual Risk Profile Assessment
performed in the first half of the year, involving 95 subsidiaries in
37 Countries and the Interim Top Risk Assessment performed in the
second half of the year, relating to the update of the evaluation and
treatment of Eni’s top risks and the main business risks. A specific
focus regarded the analysis of the de-risking effects of the digital
transformation, focusing on the main impacted risks and the mitigation
mechanisms, as well as identifying the measurement KPIs. The two
assessment results were submitted to Eni’s Management and Control
Bodies in July and December 2019. In addition, three monitoring
processes were performed on Eni’s top risks. The monitoring of such
risks and the relevant treatment plans allow to analyze the risks
evolution (through update of appropriate indicators) and the progress
in the implementation of specific treatment measures decided by
management. The top risks monitoring results were submitted to the
Management and Control Bodies in March, July and October 2019. In
2019, in order to improve the process' effectiveness and efficency
and data quality: (i) the risk assessment methodologies were
strengthened, through the introduction of new tools for assessing the
effectiveness of mitigation and economic and financial impacts; (ii) the
implementation of the Integrated Country Risk (ICR) model has been
completed; and (iii) a pilot project for the digitization of the ICR has
been realized, which will be extended to the main upstream Countries
during 2020. The risk knowledge, training and communication sub-
process is aimed at increasing the diffusion of the culture of risk, at
strengthening a common language among the resources that operate
in the risk management area across the different Eni businesses as
well as sharing information and experiences, through the development
of a risk knowledge management system. Eni’s top risks portfolio
consists of 20 risks classified in: (i) external risks, (ii) strategic risks
and, finally, (iii) operational risks (see Targets, risks and treatment
measures on the following pages). The risk related to the spread of
pandemics and epidemics, with potential impacts on people, health
system and business, is increasing, as reported on page 98.
INTEGRATED RISK MANAGEMENT PROCESS
1
RISK GOVERNANCE, METHODOLOGIES AND INSTRUMENTS
2
3
IRM
INTEGRATED RISK MANAGEMENT
Risk-based approach
RISK STRATEGY
INTEGRATED RISK MANAGEMENT
Integrated Risk Assessment
Integrated Country Risk
Contract Risk Mgmt
Integrated Project Risk Mgmt & M&A
4
RISK KNOWLEDGE, TRAINING AND COMMUNICATION
INTEGRATED RISK MANAGEMENTEni Annual Report 2019 22
Targets, risks and treatment measures
STRATEGIC RISK
SCENARIO
CLIMATE CHANGE
MAIN RISK
EVENTS
Risk of unfavourable fluctuations in Brent
and other commodities prices compared to
planning assumptions.
Climate change referred to the possibility of change in scenario/climatic conditions
which may generate physical and connected to energy transition risks (legislative,
market, technological and reputational risks) on Eni’s businesses in the short, medium
and long term.
TREATMENT
MEASURES
• Efficiency (capex and costs);
• Upstream projects portfolio with a low break
even price and reduced time-to-market;
• Hedging/coverage strategy for gas, power
and LNG exposures aimed at maximizing the
portfolio value;
• Ramp-up of green refineries, diversification
of feedstocks and end markets;
• Adoption of a new Company's mission based on the UN SDGs and definition of
strategic guidelines and targets for the energy transition in the short, medium and
long term;
• Structured governance on climate with a central role of the Board in managing
main issues connected with climate change; presence of specific committees;
establishment of the Advisory Board and Eni’s programs focused on climate
change issues;
• Inclusion of targets related to the energy transition in management incentive
• Chemical portfolio diversification addressed
plan, consistent with the medium and long term plans;
to specialties and integration with the
downstream supply chain;
• Renewable chemical and recycling.
→ Ref. pages 88-89
• Leadership on climate-related financial disclosures and participation in different
initiatives at international level.
→ Ref. pages 93-95
EXTERNAL RISK
GEOPOLITICAL
COUNTRY
MAIN RISK
EVENTS
Impact of geopolitical issues on strategic
actions and business operations.
Political and social instability in Eni’s Countries of operations may lead to acts of internal
conflicts, civil unrests, violence, sabotage and attacks, with consequent production
interruptions and losses as well as interruptions in gas supplies via pipe. Global security
risk relates to actions or fraudulent events which may negatively affect people and
material and immaterial assets. Upstream Credit and Financing risk related to the credit
proceeds delay or cost recovery from National Oil Companies (credit) or joint venture
partners (financing).
TREATMENT
MEASURES
• Institutional activities with national and
international players in order to overcome
crisis situations;
• Continuous monitoring of the environment,
mainly focused on the critical political/
institutional developments and regulatory
aspects which can potentially affect the
business;
• Enhancement of Eni’s presence leveraging
on economic and social issues of Countries
where Eni operates;
• Geographical diversification of asset portfolio since the exploration phase and business
diversification;
• Reduction of the exposure through the Dual Exploration Model;
• Keeping efficient and long-lasting relationships with producing Countries and local
stakeholders through local and social development and sustainability projects;
• Implementation of the security management system supported by specific sites and
Countries analysis of the preventive measures;
• Finalization of specific agreements on repayment plans of third parties receivables;
• Securitization package with in-kind withdrawals and/or utilization of dedicated escrow
account;
• Carry agreement negotiations and offsetting with the NOC’s through debt positions in
• Participation in the newly established Eastern
the Country.
Mediterranean Gas Forum.
→ Ref. page 88 and page 99
→ Ref. pages 99-101
OPERATIONAL RISK
ACCIDENTS
MAIN RISK
EVENTS
Blow-out risks and other accidents affecting the upstream assets, refineries and petrochemical plants, as well as the transportation of
hydrocarbons and derivatives by sea and land (i.e. fires, explosions, etc.) with damages on people and assets and impact on company
profitability and reputation.
TREATMENT
MEASURES
• Use of the Well Complexity & Economic Index classification methodology to keep the number of "level 1" wells below 30%; real-time
monitoring of the drilling phases of complex wells; finalization of the new in house technologies (Downhole Insulation Packer, Casing
Valve and well-head safety valve);
• Use of standard methodologies for simplified quantitative assessment (Quantitative Risk Assessment), in order to identify the potential
risks connected to the upstream assets (BART - Baseline Assessment Risk Tool) and IT systems for the management of Asset Integrity
and Maintenence processes (CCMS - Centralized Computing Center Management System);
• Development of innovative digital tools and big data analytics to improve operational performance and Asset Integrity. In particular, the
implementation of the Digital Lighthouse project from Val d'Agri to other upstream and downstream top value assets;
• Specific technological development and emergency management plans; specific HSE audit and plants monitoring;
• Involvement of First Parties to strengthen the culture of security in joint-control JV;
• Management and continuous monitoring of shipping operation through vetting activities on shipping and third operators.
→ Ref. pages 92-93
INTEGRATED RISK MANAGEMENT 23
Eni’s target ˛
Company profitability
Corporate Reputation
Relationship with Stakeholders, Local development
EXPOSURE TO LONG-TERM GAS
CONTRACTS
Adverse scenario on exposure to long-term gas contracts.
RELATIONSHIP WITH STAKEHOLDER
Relationships with international, national and local stakeholders on oil&gas
industry activities, with impacts also in the media.
• Renegotiations of long-term gas supply contracts;
• Continuous control of arbitration management.
→ Ref. page 101
• Integration of targets and sustainability projects (i.e. Community Investment)
within the Strategic Plan and management incentive program;
• Focused communication plans, development of dialogue initiatives and
discussion with local areas;
• Initiatives to meet and dialogue with stakeholders and strengthening of
presence in critical areas in order to intensify the relationship management
with local authorities and territories;
• Development of measurement instruments, monitoring and prediction of
corporate reputation (RepLab) for all stakeholders categories.
→ Ref. page 94
EVOLUTION IN LEGISLATION (G&P REGULATORY AND HSE LEGISLATION)
Potential deteriorating legislative/regulatory, national and international environment in the Gas & Power segment with impacts to corporate profitability.
Potential impacts on business operations and competitiveness as result of evolution and complexity of HSE legislation.
• Asset Backed Trading (ABT);
• Control of legislative and regulatory evolution aimed at business process simplification/mitigation;
• Recovery/optimization actions on logistical costs through asset backed trading activities and contractual revision on capacity commitment;
• Constant assessment of the adequacy of the existing HSE models and continuous alignment of them to the regulatory developments, through the
HSE control model, which involves the performance of technical audits and checks on regulatory compliance on sites and Certifications of the HSE
Management System;
• Constant assessment of the adequacy of the regulatory framework, through a legislative update process, based on three levels of HSE responsibility
and regulated by the MSG HSE.
→ Ref. page 102
CYBER SECURITY
INVESTIGATIONS AND PROCEEDINGS
Cyber Security & Industrial espionage refers to cyber attacks aimed at
compromising information (ICT) and industrial (ICS) systems, as well as the
subtraction of Eni's sensitive data.
Environmental, health and safety proceedings may trigger impacts on company
profitability (costs for remediation activities and/or plant implementation), operating
activities and corporate reputation. Involvement in anti-corruption investigations
and proceedings.
• Centralized governance model of Cyber Security, with units dedicated to
cyber intelligence and prevention, monitoring and management of cyber
attacks;
• Strengthening of Cyber Security Operations infrastructures and services;
• Constant updating and alignment of the rules dedicated to the information
security management and data protection;
• Operating plans aimed at increasing security of industrial sites (in Italy and
abroad), training and awareness initiatives dedicated to Eni's employees;
• Evolution, in the cyber risk detection and assessment phase, of the current
governance model according to a business oriented method.
• Enhancement of the process of assigning and managing assignments to external
professionals through new methods aimed at ensuring transparency and
traceability;
• Continuous monitoring of regulatory developments and constant evaluation of the
adequacy of existing presidium and control models;
• Internal training activities at all levels on the topics of interest;
• Monitoring of relations with the Public Administration and definition of routes for
the management of relevant problems and for the development of the territory;
• Continuous monitoring of the efficacy and efficiency of reclamation activities;
• Audit activities on compliance with anti-corruption regulations and 231 Legislative
→ Ref. page 104
Decree.
→ Ref. pages 103-104
INTEGRATED RISK MANAGEMENTEni Annual Report 2019 24
Governance
Integrity and transparency are the principles that have inspired Eni
in designing its corporate governance system1, a key pillar of the
Company’s business model. The governance system, flanking our
business strategy, is intended to support the relationship of trust
between Eni and its stakeholders and to help achieve business
goals, creating sustainable value for the long-term. Eni is committed
to building a corporate governance system founded on excellence in
our open dialogue with the market and all stakeholders.
Ongoing, transparent communication with stakeholders is an
essential tool for better understanding their needs. It is part of our
efforts to ensure the effective exercise of shareholders’ rights.
With this in mind, in 2019 Eni continued to pursue a dialogue with
the market on matters of governance, to seize the opportunities
deriving from studies and experience at the international level.
In particular, through a survey and meetings of the Chairman
with Eni's main shareholders and proxy advisors, the possible
developments of the Company's governance system were
investigated.
Investors expressed considerable appreciation for Eni's governance
system, considering it appropriate and efficient, without prejudice to
the possibility of introducing other governance solutions in line with
international approaches.
The Eni Corporate Governance
Eni Corporate Governance model
Eni’s Corporate Governance structure is based on the traditional
Italian model, which – without prejudice to the role of the
Shareholders’ Meeting – assigns the management of the Company
to the Board of Directors, supervisory functions to the Board of
Statutory Auditors and statutory auditing to the Audit Firm.
Appointment and composition of corporate bodies
Eni’s Board of Directors and Board of Statutory Auditors, and their
respective Chairmen, are elected by the Shareholders’ Meeting. To
ensure the presence of Directors and Statutory Auditors selected by
non-controlling shareholders a slate voting mechanism is used.
Eni’s Board of Directors and Board of Statutory Auditors, whose
term runs from April 2017 until the Shareholders’ Meeting called
to approve the 2019 financial statements, are made up of 9 and 5
members, respectively. Three directors and two standing statutory
auditors, including the Chairman of the Board of Statutory Auditors,
are elected by non-controlling shareholders, thereby giving minority
shareholders a larger number of representatives than that provided
for under law. In deciding the composition of the Board of Directors,
the Shareholders’ Meeting was able to take account of the guidance
provided to investors by the previous Board with regard to diversity,
professionalism, management experience and international
representation. The outcome was a balanced and diversified Board
of Directors. The composition of the Board of Directors and of the
Board of Statutory Auditors is also more diversified in gender terms,
in accordance with the provisions of applicable law and the By-laws.
[The Board prepared new shareholders’ advice with a view to its
renewal].
Moreover, the number of independent directors on the Board of
Directors (72 of the 9 serving directors, of whom 8 are non-executive
directors) remains greater than the number provided for in the By-
laws and in the Corporate Governance Code.
The structure of the Board of Directors
The Board of Directors appointed a Chief Executive Officer
and established four internal committees with advisory and
recommendation functions: the Control and Risk Committee3,
COMPOSITION OF THE BOARD OF DIRECTORS
Independence(a)
Gender diversity
Age(b)
Slate
3
2
3
1
1
2
40–50 years
51–60 years
61–70 years
71–80 years
5
6
7
6
majority
minority
independent
non independent
male
female
(a) Independence as defined by applicable law.
(b) Figures at December 31, 2019.
(1) For more detailed information on the Eni Corporate Governance system, please see the Corporate Governance and Shareholding Structure Report, which is published on the Company’s
website in the Governance section.
(2) Independence as defined by applicable law, to which the Eni By-laws refer. Under the Corporate Governance Code, 6 of the 9 serving directors are independent.
(3) As regards the composition of the Control and Risk Committee, Eni requires that at least two members shall have appropriate experience with accounting, financial or risk management issues,
exceeding the requirements of the Corporate Governance Code, which recommends only one such member. In this regard, on April 13, 2017 the Eni Board of Directors determined that 3 of the 4
members of the Committee, including the Chairman, have the appropriate experience. The level of experience of the Committee members therefore exceeds that provided for in the Committee Rules.
25
the Remuneration Committee4, the Nomination Committee and the
Sustainability and Scenarios Committee. The Committees report,
through their Chairmen, on the main issues they address at each
meeting of the Board of Directors.
The Board of Directors also retained the Chairman’s major role in
internal controls, with specific regard to the Internal Audit unit. The
Chairman proposes the appointment and remuneration of its Head and
the resources available to it, and also directly manages relations with
the unit on behalf of the Board of Directors (without prejudice to the
unit’s functional reporting to the Control and Risk Committee and the
Chief Executive Officer, as the director in charge of the internal control
and risk management system).
The Chairman is also involved in the appointment of the primary
Eni officers responsible for internal controls and risk management,
including the officer in charge of preparing financial reports, the
members of the Watch Structure, the Head of Integrated Risk
Management and the Head of Integrated Compliance. Finally, the Board
of Directors, acting on a recommendation of the Chairman, reappointed
the Secretary, keeping his role as Corporate Governance Counsel,
charged with providing assistance and advice to the Chairman, the
Board of Directors and the individual directors, reporting periodically to
the Board of Directors on the functioning of Eni’s corporate governance
system.
This report enables the periodic monitoring of the governance model
adopted by the Company, designed on the basis of the most prominent
studies in this field, the choices of our peers and the corporate
governance innovations incorporated in the corporate governance
codes of other Countries and in the principles issued by leading
international bodies, identifying any strengths and areas for additional
improvement in the Eni system. In view of this role, the Secretary, who
reports to the Board of Directors and, on its behalf, to the Chairman,
must also meet appropriate independence and other requirements 5.
The following chart summarises the Company’s corporate governance
structure as at February 27, 2020:
BOARD OF DIRECTORS
CHIEF EXECUTIVE OFFICER (CEO)
CHAIRMAN
Claudio Descalzia
Emma Marcegagliab
DIRECTORS (NON-EXECUTIVE)
Andrea Gemmad
Pietro A. Guindanic
Karina Litvackc
Alessandro Lorenzic
Diva Morianid
Fabrizio Paganie*
Domenico Livio Tromboned
C
C
C
C
M
M
M
S U ST AIN A BILIT Y
MITTEE
MITTEE
MITTEE
C O N T R O L
MIN A TIO N
MIT TEE
R E M U N E R A TIO N
C O
A N D S C E N A RIO S C O
A N D RIS K C O
C O
N O
CHAIRMAN
C
M
OFFICER
IN CHARGE
OF PREPARING
FINANCIAL REPORTS
Massimo Mondazzi
(Chief Financial Officer)
Eni SpA
Shareholders'
Meeting
SENIOR EXECUTIVE
VICE PRESIDENT
INTERNAL AUDIT
Marco Petracchini
BOARD SECRETARY
AND CORPORATE
GOVERNANCE
COUNSEL
(Company Secretary)
Roberto Ulissi***
ENI WATCH STRUCTURE
AND GUARANTOR
OF THE CODE OF ETHICS
Attilio Befera (Chairman)f
Ugo Draettaf
Claudio Varronef
Luca Franceschinig
Marco Petracchinih
Stefano Speronii
Domenico Noviellol
BOARD OF STATUTORY AUDITORS
(SOA Audit Committee)
CHAIRMAN
Rosalba Casiraghic
STATUTORY AUDITORS**
Enrico Maria Bignamic
Paola Camagnid
Andrea Parolinid
Marco Seracinid
AUDIT FIRM
PwC SpA
MAGISTRATE OF
THE COURT
OF AUDITORS
Manuela Arrigucci****
a Member appointed from the majority list.
b Member appointed from the majority list non-executive
and independent pursuant to law.
c Member appointed from the minority list and independent pursuant
to law and Corporate Governance Code.
d Member appointed from the majority list and independent pursuant
to law and Corporate Governance Code.
e Member appointed from the majority list, non-executive
and non independent.
External member.
Executive Vice President Integrated Compliance.
f
g
h
i
l
*
**
Senior Executive Vice President Internal Audit.
Senior Executive Vice President Legal Affairs.
Executive Vice President Labour Law and Dispute.
The Advisory Board is chaired by Director Fabrizio Pagani and composed of leading
international energy experts: Ian Bremmer, Christiana Figueres, Philip Lambert
and Davide Tabarelli.
The following are Alternate Auditors:
Stefania Bettoni - Member appointed from the majority list.
Claudia Mezzabotta - Member appointed from the minority list.
*** Also Senior Executive Vice President Corporate Affairs and Governance.
**** Adolfo Teobaldo De Girolamo until February 28, 2019.
(4) The Rules of the Remuneration Committee require that at least one member shall have adequate expertise and experience in finance or compensation policies. These qualifications are
assessed by the Board of Directors at the time of appointment. In this regard, on April 13, 2017 the Eni Board of Directors determined that 3 of the 4 members of the Committee have the
appropriate expertise and experience. The level of expertise and experience of the Committee members therefore exceeds that provided for in the Committee Rules.
(5) The Charter of the Board Secretary and Corporate Governance Counsel (Company Secretary) is available on the Eni website, in the Governance section.
GOVERNANCEEni Annual Report 2019
26
The following is a chart setting out the current macro-organizational structure of Eni SpA as at February 27, 2020:
R. Ulissi
Board Secretary
and Corporate
Governance Counsel
(Company Secretary)(a)
M. Petracchini
Internal Audit
Senior Executive
Vice President(b)
BOARD OF DIRECTORS
E. Marcegaglia
(Chairman of the Board)
C. Descalzi
(Chief Executive Officer)
P. Longhini
Assistant
to the Chairman
of the Board
Office of the CEO (A. Muccioli)
S. Speroni
R. Ulissi
L. Pistelli
M. Bardazzi
L. Franceschini
J. Trevisan
Legal Affairs
Senior Executive
Vice President
Corporate Affairs
& Governance
Senior Executive
Vice President
International
Affairs
Executive
Vice President
External
Communication
Executive
Vice President
Integrated
Compliance
Executive
Vice President
Integrated Risk
Management
Executive
Vice President
M. Bollini
Commercial
Negotiations
Senior Executive
Vice President
L. Lusuriello
Chief Digital
Officer
M. Mondazzi
Chief Financial
Officer
C. Granata
Chief Services
& Stakeholder
Relations Officer
A. Puliti
Chief Upstream
Officer(c)
L. Bertelli
Chief
Exploration
Officer
S. Maione
Chief Development,
Operations
& Technology
Officer(c)
L. Cosentino
Energy Solutions
Executive Vice
President
C. Signoretto
Chief Gas & LNG
Marketing
and Power
Officer(d)
G. Ricci
Chief Refining
& Marketing
Officer
(a) The Board Secretary and Corporate Governance Counsel (Company Secretary) reports hierarchically and functionally to the Board of Directors and, on its behalf, to the Chairman.
(b) The Senior Executive Vice President Internal Audit reports hierarchically to the Board of Directors and, on its behalf, to the Chairman, without prejudice to its functional reporting
to the Control and Risk Committee and to the CEO in his capacity as Director in charge of the Internal Control and Risk Management System.
(c) Since July 1, 2019.
(d) Since April 15, 2019.
Decision making
The Board of Directors entrusts the management of the
Company to the Chief Executive Officer, while retaining key
strategic, operational and organizational powers for itself,
especially as regards governance, sustainability6, internal
control and risk management.
Organizational arrangements
In recent years, the Board of Directors has devoted special
attention to the Company’s organizational arrangements, with
a number of important measures being taken with regard to the
internal control and risk management system and compliance.
More specifically, the Board decided that the Integrated Risk
Management function reports directly to the Chief Executive Officer
and created an Integrated Compliance Department, also reporting
to the Chief Executive Officer, separate from the Legal Department.
Among the Board of Directors’ most important duties is the
appointment of people to key management and control positions
in the Company, such as the officer in charge of preparing financial
(6) More specifically, the Board of Directors has reserved for itself decisions concerning the establishment of sustainability policies, the results of which are reported together with financial
results in an integrated manner in the Annual Report, as well as the examination and approval of reports covering areas not included in the integrated reporting framework. For more information
concerning non-financial disclosures, please see the section of the Report on the Consolidated Disclosure of Non-Financial Information (NFI), pursuant to Legislative Decree No. 254/2016.
GOVERNANCE 27
reports, the Head of Internal Audit, the members of the Watch
Structure and the Guarantor of the Eni Code of Ethics. In performing
these duties, the Board of Directors may draw on the support of the
Nomination Committee.
Reporting flows
In order for the Board of Directors to perform its duties as effectively
as possible, the directors must be in a position to assess the decisions
they are called upon to make, possessing appropriate expertise and
information. The current members of the Board of Directors, who
have a diversified range of skills and experience, including on the
international stage, are well qualified to conduct comprehensive
assessments of the variety of issues they face from multiple
perspectives. The directors also receive timely complete briefings on
the issues on the agenda of the meetings of the Board of Directors.
To ensure this operates smoothly, Board meetings are governed
by specific procedures that establish deadlines for providing
members with documentation and the Chairman ensures that
each director can contribute effectively to Board discussions.
The same documentation is provided to the Statutory Auditors. In
addition to meeting to perform the duties assigned to the Board
of Statutory Auditors by Italian law, including in its capacity as
the “Internal Control and Audit Committee”, and by US law in its
capacity as the “Audit Committee”, the Statutory Auditors also
participate in the meetings of the Board of Directors and the
Control and Risk Committee to ensure the timely exchange of key
information for the performance of their respective duties within
the Company’s internal control and risk management system. The
adequacy and timeliness of reporting flows is subject to periodic
review by the Board of Directors as part of the annual self-
assessment process (see next section).
Ongoing training and self-assessment
On an annual basis, the Board of Directors, with the support of an
external advisor and the oversight of the Nomination Committee,
conducts a self-assessment (the Board Review)7, for which
benchmarking against national and international best practices
and an examination of Board dynamics are essential elements,
also with a view to provide shareholders with guidance on the
most appropriate professional profiles for members of the Board.
Following the Board Review, the Board of Directors develops an
action plan, if necessary, to improve the operation of the Board
and its Committees. In addition, in determining the procedures
for the performance of the Board Review, the Eni Board also
assesses whether to perform a Peer Review of the Directors, in
which each director expresses his or her view of the contribution
made by the other Directors to the work of the Board. The Peer
Review, which has been conducted five times in the last eight
years, most recently in February 2020 in conjunction with the
Board Review, is a best practice among Italian listed companies.
Eni was among the first Italian companies to perform one,
starting in 2012.
The Board of Statutory Auditors also conducted its own
self-assessment in 2019. For a number of years now, Eni has
supported the Board of Directors and the Board of Statutory
Auditors with an induction programme, which involves the
presentation of the activities and organization of Eni by top
management. Moreover, in order to improve the understanding of
Eni’s industrial processes, the Board Induction is accompanied
by an ongoing training programme with visits to sites in Italy
and abroad. In 2019, in continuity with previous initiatives, this
included a visit to the Ruwais refinery plant complex in Abu Dhabi,
on the occasion of a meeting of the Board held abroad.
The governance of sustainability
Eni’s governance structure reflects the Company’s willingness
to integrate sustainability into its business model. The Board of
Directors has a central role in defining sustainability policies and
strategies, acting upon proposal of the CEO, in the identification
of annual, four-year and long-term objectives shared between
functions and subsidiaries and in verifying the related results,
which are also presented to the Shareholders’ Meeting.
In detail, a central theme in which the Board of Directors plays a
key role is challenge related to the process of energy transition to
a low carbon future. The Board of Directors plays a key role in these
issues, approving strategic initiatives and long-term objectives on
the matter both for the CEO and for Eni management.
During 2018, Eni ensured its contribution at the World Economic
Forum (WEF) “Climate Governance”8 initiative, with the
participation of Eni’s Board of Directors. In 2019 Eni participated in
further initiatives launched under the WEF, in particular to define a
model for assessing governance processes adopted by companies
for the management of risks and opportunities related to climate
change.
Another central theme that the Board of Directors oversees is the
respect for Human Rights. Indeed, in December 2018, the Board
of Directors of Eni SpA approved the Eni Statement on respect for
human rights. This document renews the Company’s commitment,
aligning it with the main international standards on Human Rights
and Business, starting from the United Nations Guiding Principles,
highlighting also the priority areas on which this commitment is
concentrated.
Furthermore, continuing on the path of transformation, in September
Eni's Board of Directors approved a new corporate mission,
which takes inspiration from the 17 United Nations Sustainable
Development Goals (SDGs) and highlights Eni's values related
to climate, the environment, access to energy, cooperation and
partnerships for development, respect for people and human rights.
The mission highlights the principles that underpin the Company's
business model aimed at integrating sustainability into all Company's
activities, having regard not only for climate and environment but
also for the development, enhancement and training of human
resources, considering diversity as an opportunity.
(7) For more information on the Board Review process, see the section devoted to that process in the Corporate Governance and Shareholding Structure Report 2019.
(8) The initiative seeks to increase the level of Board awareness on climate-related issues, also in the light of the recommendations of the Task Force on Climate-related Financial Disclosures (TCFD).
GOVERNANCEEni Annual Report 2019 28
THE MAIN SUSTAINABILITY ISSUES ADDRESSED BY THE BOARD IN 2019
• 2018 financial statements9, including the Non-Financial Statement;
• the Remuneration Report, including sustainability targets in the definition of performance plans;
• 2018 HSE Performance;
• 2018 Sustainability Report (Eni For);
• Sustainability scenario;
• Update of the UK Modern Slavery Act statement;
• New Eni corporate mission.
The Sustainability and Scenarios Committee
In performing its duties in the field of sustainability, the Board
is supported by the Sustainability and Scenarios Committee,
established for the first time in 2014 by the Board itself, which
provides advice and recommendations on scenario and sustainability
issues. The Committee plays a key role in addressing the
sustainability issues integrated into the Company’s business model10.
The Advisory Board
At its meeting of July 27, 2017, the Eni Board of Directors
established an Advisory Board11, chaired by the Director Fabrizio
Pagani and composed of international experts (Ian Bremmer,
Christiana Figueres, Philip Lambert and Davide Tabarelli).
The Advisory Board is charged with analysing major geopolitical,
technological and economic trends, including issues associated
with decarbonization, to support the Board itself and the Chief
Executive Officer. In 2019, the Advisory Board met two times,
in April and July, to address matters related to new
environmental regulations, green projects (forestry and
renewable energy) and to investigate the most recent
international developments.
Remuneration Policy
Eni’s Remuneration Policy for its Directors and top management
contributes to the Company’s strategy, the pursuit of the
Company's long-term interests and sustainability and is
established in accordance with the Governance model adopted
by the Company and the recommendations of the Corporate
Governance Code. The Policy seeks to attract, motivate and
retain high-level professionals and skilled managers and to
align the interests of management with the priority objective
of creating value for shareholders over the medium/long-term.
For this purpose, the remuneration of Eni’s top management is
established on the basis of the position and the responsibilities
assigned, with due consideration given to market benchmarks
for similar positions in companies similar to Eni in dimension and
complexity.
Under Eni Remuneration Policy, considerable importance is given
to the variable component, also on a per-share basis, which is
linked to the achievement of certain results, through incentive
plans connected to the fulfilment of preset, measurable and
complementary targets which represent the main Company’s
priorities in line with the Company’s Strategic Plan and the
expectations of shareholders and stakeholders, in order to
promote a strong focus on results and combine the operating,
economic and financial soundness with social and environmental
sustainability, coherently with the long-term nature of the
business and the related risk profiles. The Policy defined for the
next term 2020-2023 provides the confirmation, in the Short-Term
Plan of Incentive of Short Term with deferral, of a target related
to environmental sustainability and human capital (weight 25%)
and the introduction in the 2020-2022 Long-Term Equity Incentive
Plan, of a target related to environmental sustainability and
energy transition (overall weight 35%), articulated on a series
of goals linked to the processes of decarbonization and energy
transition and to the circular economy. The Remuneration Policy
is described in the first section of the Remuneration Report,
available on the Company’s website (www.eni.com) and is
presented for a binding vote at the Shareholders’ Meeting, with
the cadence required by its duration and in any case at least
every three years or in the event of changes to it12.
(9) This is an integrated report that enables Eni’s stakeholders, including non-investors, to understand the connections between financial performance and the outcomes of actions in the
environmental and social fields, in accordance with Eni’s integrated business model.
(10) For more information on the Committee activities in 2019, please see the relevant section in the Corporate Governance and Shareholding Structure Report 2019.
(11) For more information, please see the Eni website, in the Governance section.
(12) In accordance with Art. 123 ter, paragraph 3 bis of the Italian Decree Law No. 58/98.
GOVERNANCE 29
2019 TARGETS FOR THE 2020 SHORT-TERM INCENTIVE PLAN WITH DEFERRAL
ECONOMIC AND FINANCIAL
RESULTS
(25%)
OPERATING RESULTS
AND SUSTAINABILITY
OF ECONOMIC RESULTS (25%)
ENVIRONMENTAL
SUSTAINABILITY AND HUMAN
CAPITAL (25%)
EFFICIENCY AND FINANCIAL
STRENGTH
(25%)
INDICATORS
Earning Before Tax (12.5%)
Free cash flow (12.5%)
INDICATORS
Hydrocarbon production (12.5%)
Exploration resources (12.5%)
INDICATORS
CO2 emissions (12.5%)
Severity Incident Rate (12.5%)
INDICATORS
ROACE adjusted (12.5%)
Net Debt/EBITDA adjusted (12.5%)
LEVERS
Upstream expansion
Strengthen Gas & Power operations
Resilience in downstream
Green business
LEVERS
Fast track approach
Expanding exploration acreage
Diversification
LEVERS
Decarbonization
HSE and sustainability
LEVERS
Financial discipline
Efficiency of operating costs and G&A
Optimisation of working capital
The internal control and risk management system13
Eni has adopted an integrated and comprehensive internal
control and risk management system at different levels of the
organizational and corporate structure, based on reporting tools,
organizational units, regulations, corporate rules and reporting
flows between the various control levels and to the management
and control bodies of the Company and its subsidiaries. The internal
control and risk management system is also based on Eni’s Code
of Ethics, which sets out the rules of conduct for the appropriate
management of the Company’s business and which must be
complied with by all the members of the Board, as well as of the
other corporate bodies and all Eni personnel. Eni has adopted
rules for the integrated governance of the internal control and
risk management system, the guidelines of which, approved by
the Board, set out the duties, responsibilities and procedures for
coordinating between the primary system actors. At its meeting
of October 25, 2018, the Board updated these guidelines, also to
reflect recent developments in internal organization and rules
concerning Integrated Compliance.
Indeed, in 2018 Eni completed the definition of the reference
model for Integrated Compliance, which together with Model 231
and the Code of Ethics, is aimed at ensuring that all Eni personnel
who are contributing to the achievement of business objectives
operate in full compliance with the rules of integrity and applicable
laws and regulations in an increasingly complex national and
international regulatory framework, defining a comprehensive
process, developed using a risk-based approach, for managing
activities to prevent non-compliance. With this in mind, risk
assessment methodologies were developed aimed at modulating
controls, calibrating monitoring activities and planning training and
communication activities based on the compliance risk underlying
the various cases, to maximize their effectiveness and efficiency.
The Integrated Compliance process was designed to stimulate
integration between those who work in the business activities and
the corporate functions that oversee the various compliance risks,
both internal or external to the Integrated Compliance Department.
Furthermore, in October 2018, acting on the proposal of the Chief
Executive Officer, having obtained a favourable opinion from
the Control and Risk Committee, the Board of Directors of Eni
approved the internal rules concerning the Market Information
Abuse (Issuers). These, by updating the previous Eni rules for
the aspects relating to “issuers”, incorporate the amendments
introduced by Regulation No. 596/2014/EU of April 16, 2014
and the associated implementing rules, as well as the national
regulations, taking account of Italian and foreign institutional
guidelines on the matter. The updated internal rules lay down
principles of conduct for the protection of confidentiality
of corporate information in general, to promote maximum
compliance, as also required by Eni’s Code of Ethics and corporate
security measures. Eni recognizes that information is a strategic
asset to be managed in such a way as to ensure the protection of
the interests of the Company, shareholders and the market.
An integral part of the Eni internal control system is the internal
control system for financial reporting, the objective of which is to
provide reasonable certainty of the reliability of financial reporting
and the ability of the financial report preparation process to
generate such reporting in compliance with generally accepted
international accounting standards. Eni’s CEO and Chief Financial
Officer (CFO) are responsible for planning, establishing and
maintaining the internal control system for financial reporting.
The CFO also serves as the officer in charge of preparing financial
reports. A central role in the Company’s internal control and
risk management system is played by the Board of Statutory
Auditors, which in addition to the supervisory and control
functions provided for in the Consolidated Law on Financial
Intermediation, also monitors the financial reporting process and
the effectiveness of the internal control and risk management
systems, consistent with the provisions of the Corporate
Governance Code, including in its capacity as the “Internal Control
and Audit Committee” pursuant to Italian law and as the “Audit
Committee” under US law.
(13) For more information, please see the Corporate Governance and Shareholding Structure Report 2019.
GOVERNANCEEni Annual Report 2019 30
Exploration
& Production
KEY PERFORMANCE INDICATORS
TRIR (Total Recordable Injury Rate)
of which: employees
contractors
Sales from operations(a)
Operating profit (loss)
Adjusted operating profit (loss)
Adjusted net profit (loss)
Capital expenditure
Profit per boe(b)
Opex per boe(c)(d)
Finding & Development cost per boe(c)(e)
Average hydrocarbon realization
Hydrocarbons production(c)
Net proved hydrocarbon reserves
Reserves life index
Organic reserves replacement ratio
Employees at year end
of which outside Italy
Oil spills due to operations (>1 barrel)
CO2 equivalent from methane fugitive emissions
Volumes of hydrocarbon sent to process flaring
GHG emissions/100% operated hydrocarbon
gross production(f)
(total recordable injuries/worked hours) X 1,000,000
(€ milllion)
($/boe)
(kboe/d)
(mmboe)
(years)
(%)
(number)
(barrels)
(mmtonnes CO2eq)
(billion Sm3)
2019
2018
2017
0.33
0.18
0.37
23,572
7,417
8,640
3,436
6,996
5.1
6.4
15.5
43.54
1,871
7,268
10.6
92
11,502
6,946
988
0.56
1.2
0.30
0.29
0.30
25,744
10,214
10,850
4,955
7,901
9.3
6.8
10.4
47.48
1,851
7,153
10.6
100
11,645
7,114
1,595
1.08
1.4
0.28
0.23
0.30
19,525
7,651
5,173
2,724
7,739
8.7
6.6
10.4
35.06
1,816
6,990
10.5
103
11,970
7,460
3,022
1.14
1.6
(tonnes CO2eq/kboe)
19.58
21.44
22.75
(a) Before elimination of intragroup sales.
(b) Related to consolidated subsidiaries.
(c) Includes Eni's share of equity-accounted entities.
(d) If calculated under unchanged account criteria vs. comparative periods, opex per boe for the year 2019 would be 6.9 $/boe.
(e) Three-year average.
(f) Hydrocarbon gross production from fields fully operated by Eni (Eni’s interest 100%) amounting to 1,114 mmboe, 1,067 mmboe and 998 mmboe in 2019, 2018 and 2017, respectively.
Performance of the year
˛ Total recordable injury rate (TRIR) was 0.33, up by 10% as a result
of higher number of accidents registered among the contractors.
following preventive maintenance, review of integrated anti-
corrosion plans and replacement of lines sections.
˛ Oil spills due to operations decreased by 38% from 2018,
˛ Methane fugitive emissions were down by 48% from 2018
31
and by 81% from 2014, achieving the 2025 target six years in
advance, due to the completion of the monitoring campaigns and
maintenance activities planned during the year.
˛ Volumes of hydrocarbon sent to process flaring were down by
15% from 2018 and down by 29% from 2014. Confirmed the target
of zero flaring by 2025.
˛ Upstream GHG intensity index was positive with a reduction of 9%
from 2018 and 27% from the 2014 baseline, in line with the 2025
target.
˛ In 2019, the E&P segment recorded an adjusted operating profit
of €8,640, up by 7%, excluding the impact of the loss of control
over Eni Norge which occurred at the end of 2018 to allow
a-like-for-like comparison, and net of scenario effects, IFRS 16
accounting and the impact of lower interest rates on the present
value of the asset retirement cost resulting in higher DD&A.
˛ Oil and natural gas production was 1.871 million boe/d, up by 5%
from 2018 excluding the termination of the Intisar production
contract in Libya from the third quarter of 2018 and net of price
and portfolio effects. Start-ups and ramp-ups added 253 kboe/d
to the production level of 2019.
˛ Net proved reserves at December 31, 2019 amounted to 7.3
bboe based on a reference Brent price of $63 per barrel. The all-
sources replacement ratio was 117%, 92% of organic replacement
ratio (100% net of price effects); 98% three-year average organic
replacement ratio. The reserves life index was 10.6 years (10.6
years in 2018)
Portfolio management
˛ Vår Energi, the joint venture between Eni (69.6%) and
˛ Signed a farm-in agreement with ExxonMobil for the acquisition
HitecVision (30.4%), finalized the acquisition of ExxonMobil’s
upstream assets in Norway, effective since January 1, 2019,
with annual production of 150 kboe/d, for a total consideration
of $4.5 billion fully financed by the JV. This strategic deal will
make Vår Energi the second biggest upstream player in Norway
and boost the production target until 350 kboe/d by 2023
thanks to the development of the JV portfolio of projects.
˛ Divested to Qatar Petroleum Eni’s interests in exploration
permits in Morocco, Mozambique and Kenya, the latter
awaiting ratification.
of a 10% interest of three offshore blocks in Mozambique.
˛ Divested to Neptune Energy a 20% interest in the East
Sepinggan block in Indonesia, which includes the Merakes
discovery. Following this transaction, Eni retains the
operatorship with a 65% interest.
˛ Finalized the acquisition of a 49% interest of three concessions
in the Berkine Nord basin in Algeria. Production start-up was
achieved by means of the Eni’s model of the discoveries
fast-track development, which maximizes the projects' value
leveraging on synergies with existing facilities.
Exploration activity
˛ Exploration activity is also a distinctive approach of Eni's
upstream model, ensuring a large amount of resources at
low costs, flexibility in the short-term and fueling growth over
the long-term. In 2019 additions to the Company's reserve
backlog were 820 million of boe of new equity resources, with
an exploration cost of 1.5 $/boe. Main discoveries or appraisal
activities were in:
- Egypt, with a gas discovery in the Nour exploration prospect
(Eni operator with a 40% interest). Near-field discoveries in
the Western Desert, in the Nile Delta and Gulf of Suez, which
were already linked to existing facilities;
- Angola, achieved excellent results in the offshore Block
15/06 (Eni operator with a 36.84% interest) with three
discoveries (Agogo, Ndungu and Agidigbo), which including
the discoveries of the end of 2018 (Kalimba and Afoxè) have
increased the block’s additional mineral potential to 2 billion
barrels of oil in place;
- Ghana, with the Akoma-1 gas and NGLs discovery in the Cape
Three Points Block 4 license (Eni’s interest 42.47%), located
near the existing production facilities;
- Vietnam, with a gas and NGLs discovery in the Ken Bau
prospect in the offshore Block 114 (Eni operator with
a 50% interest);
- near-field discovery in the Niger Delta, already linked to the
existing production facilities;
- Norwegian North Sea with three oil and gas discoveries in
the PL 869 license participated by Vår Energi;
- first gas and NGLs discovery in the Emirate of Sharjah (UAE)
in the Mahani-1 exploration prospect, in just one year after
the signing of concession agreements;
- other exploration successes were reported in Algeria and Gabon.
˛ Reloading Eni’s mineral interest portfolio in 2019, acquired new
exploration acreage covering 36,000 square kilometers.
In particular, in:
- Egypt, new exploration onshore blocks in the Western Desert
and in the Nile Delta;
- Norway, Vår Energi awarded 13 licenses, of which 4 are
operated. In January 2020, awarded 17 exploration licenses,
of which 7 are operated;
- Angola, with the offshore block 1/14 (Eni operator with
a 35% interest) and the onshore Cabinda Centro license
(Eni’s interest 42.5%), these latter waiting to be ratified by
relevant authority;
- Ghana, with the operatorship of the offshore WB03 block
(Eni’s interest 70%). Contractual clauses governing mineral
license are being defined with the Country's authorities;
Eni Annual Report 2019OPERATING REVIEW | EXPLORATION & PRODUCTION 32
- the United Arab Emirates: (i) the operatorship of the Block
1 and 2 with a 70% interest, located offshore Abu Dhabi; (ii)
three onshore exploration concessions in the Emirate of
Sharjah with a 75% interest in the operated concession Area
A and C and a 50% interest in the participated concession
Area B; and (iii) the operatorship with a 90% interest in the
Block A, located offshore Emirate of Ras al Khaimah;
- signed an Exploration and Production Sharing Agreement
(EPSA) for the offshore Block 1, in Bahrain. Following this
agreement, Eni strengthens its presence in Bahrain, in line
with its strategy aimed at diversifying exploration portfolio
across basins with liquid hydrocarbon potential;
- signed a protocol with the Kazakh Ministry of Energy and
KazMunayGas (KMG) for the transfer to Eni the 50% stake
for exploration and production activities in the Abay offshore
block, located in the Caspian Sea. The Abay block will be
operated by a joint operating company established by KMG
and Eni on a 50/50 basis;
-
Indonesia, the West Ganal exploration block (Eni operator
with a 40% interest) located in the deep water Kutei Basin,
effective since January 1, 2020. The block includes the
Maha discovery and other exploration potential areas, where
development activities will be supported by the synergies
with existing facilities;
- other licenses were acquired in Algeria, Argentina, Cyprus,
Ivory Coast, Mexico, Mozambique, Tunisia and Albania, the
latter ratified by the Authorities in March 2020.
˛ In 2019 exploration expenses were €489 million (€380 million
in 2018) and included the write-off of unsuccessful wells
amounting to €214 million (€93 million in 2018), which also
related to the write-off of unproved exploration rights, if any,
associated to projects with negative outcome. The write-off
of expenses related to unsuccessful drilling activities mainly
concerned projects in n Australia, Kazakhstan, Pakistan, China
and the United Kingdom. In addition, 98 exploratory drilled
wells are in progress at year-end (47.7 net to Eni).
Development activity
˛ During the year achieved the production start-up of the
following projects:
-
-
-
-
in the Area 1, offshore Mexico, early production in just 11
months from the final investment decision (FID);
in Egypt, the Baltim South West gas project in the Great Nooros
Area, in just 19 months from the FID, and recents near-field
oil discoveries in the South West Meleiha and Sidri South
development areas;
in Algeria, in the Berkine Nord area where oil and gas
production start-up, the latter in 2020, was achieved with a
fast-track resources development;
in the United Arab Emirates, the Nasr Full Field Development
in the Umm Shaif/Nasr concession (Eni’s interest 10%), where
production ramped up;
- Trestakk project, participated by Vår Energi, in Norway;
-
in January 2020, production started up at the Agogo oil field
in the offshore Block 15/06 in Angola, in just 9 months from
discovery, leveraging on the synergies with the existing FPSOs
in the area.
˛ During the year completed the planned activities of the projects
achieving production ramp-up at the: Zohr field in Egypt;
Wafa compression and Bahr Essalam phase 2 projects, which
were started up in 2018, in Libya; OCTP project in Ghana; the
development activities of the operated Block 15/06 in Angola, as
well as certain projects in Nigeria.
project of the Bonny liquefaction plant, owned by Nigeria LNG,
to reach more than 30 MTPA of capacity by 2024, Berkine
Nord phase 2 in Algeria, Dalma in the United Arab Emirates,
Agogo in Angola as well as Balder X in Norway as part of the
Vår Energi portfolio.
˛ Programs are ongoing to improve access to energy in Africa. In
particular, during the year, we completed the expansion of the
power generation capacity at the CEC plant (Eni's interest 20%)
in Congo and Okpai plant in Nigeria as well as the rehabilitation of
certain power plants in Libya; the Takoradi-Tema interconnection
project in Ghana to deliver natural gas also in the eastern
part of the Country; other initiatives in Angola, Mozambique
and Indonesia. These activities confirmed Eni’s commitment
to support access to energy, particularly in Africa, and as
integrated in our business model.
˛ Collaboration agreement moved forward with the Food and
Agriculture Organization (FAO) to promote access to safe and
clean water in Nigeria, in particular in the north-east area, by
drilling boreholes powered by photovoltaic systems, both for
domestic use and irrigation purposes. In particular in 2018-2019
we realized 16 wells.
˛ Development expenditure amounted to €6 billion, directed
mainly outside Italy, in particular in Egypt, Nigeria, Kazakhstan,
Indonesia, Mexico, the United States and Angola.
˛ In 2019, overall R&D expenditure amounted to €71 million (€96
˛ Made final investment decision at five projects: the expansion
million in 2018).
OPERATING REVIEW | EXPLORATION & PRODUCTION 33
RESERVES
OVERVIEW
The Company has adopted comprehensive classification criteria for
the estimate of proved, proved developed and proved undeveloped
oil and gas reserves in accordance with applicable US Securities
and Exchange Commission (SEC) regulations, as provided for in
Regulation S-X, Rule 4-10. Proved oil and gas reserves are those
quantities of liquids (including condensates and natural gas
liquids) and natural gas which, by analysis of geoscience and
engineering data, can be estimated with reasonable certainty
to be economically producible from a given date forward, from
known reservoirs, under existing economic conditions, operating
methods, and government regulations prior to the time at which
contracts providing the right to operate expire, unless evidence
indicates that renewal is reasonably certain.
Oil and natural gas prices used in the estimate of proved reserves
are obtained from the official survey published by Platt's
Marketwire, except when their calculation derives from existing
contractual conditions. Prices are calculated as the unweighted
arithmetic average of the first-day-of-the-month price for each
month within the 12-month period prior to the end of the reporting
period. Prices include consideration of changes in existing prices
provided only by contractual arrangements.
Engineering estimates of the Company's oil and gas reserves
are inherently uncertain. Although authoritative guidelines
exist regarding engineering criteria that have to be met before
estimated oil and gas reserves can be designated as “proved”,
the accuracy of any reserve estimate is a function of the quality
of available data and engineering and geological interpretation
and evaluation. Consequently, the estimated proved reserves of
oil and natural gas may be subject to future revision and upward
and downward revisions may be made to the initial booking of
reserves due to analysis of new information. Proved reserves to
which Eni is entitled under concession contracts are determined
by applying Eni's share of production to total proved reserves of
the contractual area, in respect of the duration of the relevant
mineral right. Proved reserves to which Eni is entitled under PSAs
are calculated so that the sale of production entitlements should
cover expenses incurred by the Group to develop a field (Cost Oil)
and on the Profit Oil set contractually (Profit Oil). A similar scheme
applies to service contracts.
RESERVES GOVERNANCE
Eni retains rigorous control over the process of booking proved
reserves, through a centralized model of reserves governance. The
Reserves Department of the Exploration & Production segment is in
charge of: (i) ensuring the periodic certification process of proved
reserves; (ii) continuously updating the Company's guidelines on
reserves evaluation and classification and the internal procedures;
and (iii) providing training of staff involved in the process of
reserves estimation. Company guidelines have been reviewed by
DeGolyer and MacNaughton (D&M), an independent petroleum
engineering company, which has stated that those guidelines
comply with the SEC regulations1. D&M has also stated that the
Company guidelines provide reasonable interpretation of facts
and circumstances in line with generally accepted practices in the
industry whenever SEC rules may be less precise. When participating
in exploration and production activities operated by others entities,
Eni estimates its share of proved reserves on the basis of the above
guidelines.
The process for estimating reserves, as described in the internal
procedure, involves the following roles and responsibilities: (i) the
business unit managers (geographic units) and Local Reserves
Evaluators (LRE) are in charge with estimating and classifying gross
reserves including assessing production profiles, capital expenditure,
operating expenses and costs related to asset retirement obligations;
(ii) the petroleum engineering department and the operations unit
at the head office verify the production profiles of such properties
where significant changes have occurred and operating expenses,
respectively; (iii) geographic area managers verify the commercial
conditions and the progress of the projects; (iv) the Planning and
Control Department provides the economic evaluation of reserves;
and (v) the Reserves Department, through the Headquarter
Reserves Evaluators (HRE), provides independent reviews of
fairness and correctness of classifications carried out by the above
mentioned units and aggregates worldwide reserves data.
The head of the Reserves Department attended the "Università degli
Studi di Milano" and received a Physics Degree in 1988. He has more
than 30 years of experience in the oil and gas industry and more than
20 years of experience in evaluating reserves.
Staff involved in the reserves evaluation process fulfils the
professional qualifications requested by the role and complies with
the required level of independence, objectivity and confidentiality
in accordance with professional ethics. Reserves Evaluators
qualifications comply with international standards defined by the
Society of Petroleum Engineers.
RESERVES INDEPENDENT EVALUATION
Since 1991, Eni has requested qualified independent oil
engineering companies to carry out an independent evaluation2
of part of its proved reserves on a rotational basis. The description
of qualifications of the persons primarily responsible for the
reserves audit is included in the third party audit report3. In the
preparation of their reports, independent evaluators rely, upon
information furnished by Eni without independent verification,
with respect to property interests, production, current costs of
operations and development, sale agreements, prices and other
factual information and data that were accepted as represented
by the independent evaluators. These data, equally used by Eni
in its internal process, include logs, directional surveys, core
and PVT (Pressure Volume Temperature) analysis, maps, oil/
gas/water production/injection data of wells, reservoir studies,
technical analysis relevant to field performance, development
plans, future capital and operating costs.
(1) The reports of independent engineers are available on Eni website eni.com section Publications/Integrated Annual Report 2016.
(2) From 1991 to 2002, DeGolyer and MacNaughton; from 2003, also Ryder Scott. In 2018, the Societé Generale de Surveillance also provided an independent certification.
(3) The reports of independent engineers are available on Eni website eni.com section Publications/Annual Report 2019.
Eni Annual Report 2019OPERATING REVIEW | EXPLORATION & PRODUCTION 34
In order to calculate the net present value of Eni's equity
reserves, actual prices applicable to hydrocarbon sales, price
adjustments required by applicable contractual arrangements
and other pertinent information are provided by Eni to third
party evaluators. In 2019 Ryder Scott Company, DeGolyer
and MacNaughton provided an independent evaluation of
approximately 31% of Eni’s total proved reserves at December 31,
20194, confirming, as in previous years, the reasonableness of
Eni internal evaluation5.
In the 2017-2019 three-year period, 86% of Eni total proved
reserves were subject to independent evaluation. As at December
31, 2019, Zohr in Egypt was the main Eni property, which did
not undergo an independent evaluation in the last three years.
Management expects that the Zohr field will be subject to an
independent evaluation in 2020.
MOVEMENTS IN NET PROVED RESERVES
Eni's net proved reserves were determined taking into account
Eni's share of proved reserves of equity-accounted entities.
Movements in Eni's 2019 proved reserves were as follows:
Estimated net proved reserves at December 31, 2018
Extensions, discoveries, revisions of previous estimates
and improved recovery, excluding price effect
Price effect
Reserve additions, total
Portfolio
Production of the year
Estimated net proved reserves at December 31, 2019
Reserves replacement ratio, all sources
Reserves replacement ratio, organic
Organic reserves replacement ratio, net of price effect
(mmboe)
(%)
(a) See note (c) of the annual and daily oil and natural gas production tables.
Consolidated
subsidiaries
6,356
618
(58)
560
(8)
(621)
6,287
Equity-accounted
entities
797
68
68
178
(62)
981
686
(58)
Total
7,153
628
170
(683)(a)
7,268
117
92
100
Net proved reserves as of December 31, 2019 were 7,268 mmboe,
of which 6,287 mmboe of consolidated subsidiaries. Net additions
to proved reserves were 628 mmboe and derived from: (i) new
extensions and discoveries were up by 107 mmboe mainly due to
the final investment decision (FID) made for the projects Dalma in
the United Arab Emirates, Assa North in Nigeria and Agogo in Angola;
and (ii) revisions of previous estimates were up by 521 mmboe and
derived from the upward revisions of certain gas fields in Nigeria to
feed the expansion project of the Bonny liquefaction plant as well as
the progress in development activities at the Zohr in Egypt, Kashagan
in Kazakhstan, Berkine Nord in Algeria and Balder X in Norway.
Net additions were impacted by unfavorable price effects, leading to a
downward revision of 58 mmboe, mainly due to a decreased of Brent
price used in the reserves estimation process and of production gas
prices in 2019 compared to 2018, with effects on volume entitlements
at PSA contracts and on volumes of reserves which have become
uneconomical in that environment.
Portfolio transactions of 170 mmboe comprised: (i) the purchase
of ExxonMobil’s upstream assets in Norway; (ii) the purchase of a
100% interest of Oooguruk production field in Alaska; and (iii) the
disposal of production assets in Ecuador, of a 20% interest at the
Merakes discovery in Indonesia as well as other minor assets in
Norway.
The organic reserves replacement ratio6 was 92% and all sources
additions was 117%.
The reserves life index was 10.6 years (10.6 years in 2018).
PROVED UNDEVELOPED RESERVES
Proved undeveloped reserves as of December 31, 2019 totaled 2,114
mmboe, of which 1,113 mmbbl of liquids mainly concentrated in Africa
and Asia and 5,415 bcf of natural gas particularly located in Africa.
Proved undeveloped reserves of consolidated subsidiaries amounted
to 905 mmbbl of liquids and 5,041 bcf of natural gas. Movements in
Eni's 2019 proved undeveloped reserves were as follows:
(mmboe)
Proved undeveloped reserves as of December 31, 2018
Additions
Extensions and discoveries
Revisions of previous estimates
Purchases of minerals in place
Sales of minerals in place
Proved undeveloped reserves as of December 31, 2019
2,309
(655)
101
327
44
(12)
2,114
(4) Includes Eni’s share of proved reserves of equity accounted entities.
(5) The reports of independent engineers are available on Eni website eni.com section Publications/Annual Report 2019.
(6) Organic ratio of changes in proved reserves for the year resulting from revisions of previously reported reserves, improved recovery, extensions and discoveries, to production for the
year. All sources ratio includes sales or purchases of minerals in place. A ratio higher than 100% indicates that more proved reserves were added than produced in a year. The Reserves
Replacement Ratio is not an indicator of future production because the ultimate development and production of reserves is subject to a number of risks and uncertainties. These include the
risks associated with the successful completion of large-scale projects, including addressing ongoing regulatory issues and completion of infrastructure, as well as changes in oil and gas
prices, political risks and geological and environmental risks.
OPERATING REVIEW | EXPLORATION & PRODUCTION 35
In 2019, total proved undeveloped reserves decreased by 195
mmboe mainly due to: (i) progress in maturing PUDs to proved
developed (655 mmboe); (ii) new discoveries and extensions
(101 mmboe), mainly due to the FIDs made for the Dalma
project in the United Arab Emirates, the Assa North project in
Nigeria and the Agogo field in Angola; (iii) revisions of previous
estimates were up by 327 mmboe and derived mainly from
the expansion of the LNG plant of Bonny in Nigeria and the
progress in development activities of Zohr project in Egypt;
(iv) disposals (12 mmboe) of the 20% interest of the project
Merakes in Indonesia and other minor assets in Norway; and
(v) purchases (44 mmboe) mainly related to the Vår Energi
acquisition in Norway as mentioned above.
During 2019, Eni matured 655 mmboe of proved undeveloped
reserves to proved developed reserves due to progress in
development activities, production start-ups and project
revisions. The main reclassifications to proved developed
reserves are related to the following fields/projects: Zohr
and Nidoco North West in Egypt, Kashagan in Kazakhstan,
Litchendjili in Congo, Ngl Eleme in Nigeria and Area 1 project
in Mexico.
In 2019, capital expenditure amounted to approximately €6.8 billion.
Reserves that remain proved undeveloped for five or more
years are a result of several factors that affect the timing of
the projects development and execution, such as the complex
nature of the development project in adverse and remote
locations, physical limitations of infrastructures or plant
capacity and contractual limitations that establish production
levels. The Company estimates that approximately 0.5 bboe of
proved undeveloped reserves have remained undeveloped for
five years or more at the balance sheet date and decreased
0.1 bboe from 2018 mainly due to the progress in development
activities made at the Kashagan field in Kazakhstan and by
the Bahr Essalam phase 2 and Wafa compression projects in
Libya. The proved undeveloped reserves that have remained
undeveloped for five years or more at the balance sheet date
mainly related to: (i) the Zubair field in Iraq (0.1 bboe), where
development of PUDs has been conditioned by the drilling of
additional production and injection wells to be linked to the
production facilities, which were already completed to achieve the
full field production plateau of 700 kbbl/d; (ii) certain Libyan gas
fields (0.3 bboe) where development completion and production
start-ups are planned according to the delivery obligations set
forth in a long-term gas supply agreement currently in force; and
(iii) other fields in Italy and Egypt (0.1 bboe), where development
activities are in progress.
Eni Annual Report 2019OPERATING REVIEW | EXPLORATION & PRODUCTION 36
Estimated net proved hydrocarbons reserves
Consolidated subsidiaries
Italy
Developed
Undeveloped
Rest of Europe
Developed
Undeveloped
North Africa
Developed
Undeveloped
Egypt
Developed
Undeveloped
Sub-Saharan Africa
Developed
Undeveloped
Kazakhstan
Developed
Undeveloped
Rest of Asia
Developed
Undeveloped
Americas
Developed
Undeveloped
Australia and Oceania
Developed
Undeveloped
Total consolidated subsidiaries
Developed
Undeveloped
Equity-accounted entities
Rest of Europe
Developed
Undeveloped
North Africa
Developed
Undeveloped
Sub-Saharan Africa
Developed
Undeveloped
Rest of Asia
Developed
Undeveloped
Americas
Developed
Undeveloped
Total equity-accounted entities
Developed
Undeveloped
)
l
b
b
m
m
(
s
d
i
u
q
i
L
194
137
57
41
37
4
468
301
167
264
149
115
694
519
175
746
682
64
491
245
246
225
148
77
1
1
3,124
2,219
905
424
219
205
12
12
10
7
3
31
31
477
269
208
Total including equity-accounted entities
Developed
Undeveloped
3,601
2,488
1,113
s
a
g
l
a
r
u
t
a
N
)
f
c
b
(
2019
752
657
95
262
242
20
2,738
1,374
1,364
5,191
4,777
414
4,103
1,858
2,245
1,969
1,969
1,349
685
664
240
186
54
507
322
185
17,111
12,070
5,041
772
597
175
14
14
287
88
199
1,648
1,648
2,721
2,347
374
19,832
14,417
5,415
s
n
o
b
r
a
c
o
r
d
y
H
)
e
o
b
m
m
(
333
258
75
89
82
7
974
553
421
1,225
1,033
192
1,453
863
590
1,108
1046
62
742
372
370
268
182
86
95
61
34
6,287
4,450
1,837
567
330
237
16
16
63
23
40
335
335
981
704
277
)
l
b
b
m
m
(
s
d
i
u
q
i
L
s
a
g
l
a
r
u
t
a
N
)
f
c
b
(
208
156
52
48
44
4
493
317
176
279
153
126
718
551
167
704
587
117
476
252
224
252
143
109
5
5
3,183
2,208
975
297
154
143
11
11
12
8
4
37
32
5
357
205
152
2018
1,199
980
219
320
300
20
2,890
1,447
1,443
5,275
3,331
1,944
3,506
1,871
1,635
1,989
1,846
143
1,217
822
395
277
154
123
651
452
199
17,324
11,203
6,121
360
276
84
14
14
310
57
253
1,716
1,716
2,400
2,063
337
19,724
13,266
6,458
s
n
o
b
r
a
c
o
r
d
y
H
)
e
o
b
m
m
(
428
336
92
106
99
7
1,022
582
440
1,246
764
482
1,361
895
466
1,066
925
141
700
403
297
302
170
132
125
87
38
6,356
4,261
2,095
363
205
158
14
14
68
17
51
352
347
5
797
583
214
)
l
b
b
m
m
(
s
d
i
u
q
i
L
s
a
g
l
a
r
u
t
a
N
)
f
c
b
(
215
169
46
360
219
141
476
306
170
280
203
77
764
546
218
766
547
219
232
81
151
162
144
18
7
5
2
3,262
2,220
1,042
12
12
12
6
6
136
25
111
160
43
117
2017
1,131
987
144
896
771
125
3,145
1,233
1,912
4,351
1,421
2,930
3,660
1,693
1,967
2,108
1,878
230
1,065
862
203
225
171
54
709
519
190
17,290
9,535
7,755
14
14
349
83
266
1,819
1,819
2,182
1,916
266
s
n
o
b
r
a
c
o
r
d
y
H
)
e
o
b
m
m
(
422
350
72
525
360
165
1,052
532
520
1,078
463
615
1,436
856
580
1,150
891
259
427
238
189
203
176
27
137
101
36
6,430
3,967
2,463
14
14
75
20
55
1
1
470
359
111
560
394
166
7,153
4,844
2,309
3,422
2,263
1,159
19,472
11,451
8,021
6,990
4,361
2,629
7,268
5,154
2,114
3,540
2,413
1,127
OPERATING REVIEW | EXPLORATION & PRODUCTION
37
DELIVERY COMMITMENTS
Eni, through consolidated subsidiaries and equity-accounted
entities, sells crude oil and natural gas from its producing operations
under a variety of contractual obligations. Some of these contracts,
mostly relating to natural gas, specify the delivery of fixed and
determinable quantities.
Eni is contractually committed under existing contracts or
agreements to deliver in the next three years mainly natural gas to
third parties for a total of approximately 555 mmboe from producing
assets located mainly in Algeria, Australia, Egypt, Ghana, Indonesia,
Libya, Nigeria, Norway and Venezuela.
The sales contracts contain a mix of fixed and variable pricing
formulas that are generally indexed to the market price for
crude oil, natural gas or other petroleum products. Management
believes it can satisfy these contracts from quantities available
mainly from production of the Company’s proved developed
reserves and supplies from third parties based on existing
contracts. Production is expected to account for approximately
91% of delivery commitments. Eni has met all contractual
delivery commitments as of December 31, 2019.
OIL AND GAS PRODUCTION
In 2019, oil and natural gas production averaged 1,871 kboe/d.
When excluding portfolio and price effects, the production reported
an increase of 1.7%; up by approximately 5% net to the termination
of the Intisar production contract in Libya from the third quarter
of 2018. This performance was driven by ramp-ups of Zohr field
and of other fields started in 2018, mainly in Libya, Ghana and
Angola, and by the 2019 new project start-ups in Mexico, Norway,
Egypt and Algeria (with a total contribution of 253 kboe/d). Other
production increases were reported in Nigeria, Kazakhstan and the
United Arab Emirates. These positives were partly offset by lower
gas production in Indonesia reflecting a significant slowdown in
gas demand in Asia, in Venezuela, due to the current situation in the
Country, as well as mature fields decline, mainly in Italy and Angola.
Liquids production amounted to 893 kbbl/d. Start-ups and
ramp-ups of the period, mainly in Mexico, Libya and Ghana,
and production growth in the United Arab Emirates and Nigeria
were partly offset by facility shutdowns, mainly in Congo, lower
production in Venezuela and mature fields decline.
Natural gas production amounted to 5,287 mmcf/d. Ramp-ups of
the period, mainly in Egypt and Ghana, and the growth in Nigeria
were partly offset by lower production in Indonesia and Venezuela
as well as by mature fields decline.
Oil and gas production sold amounted to 630.6 mmboe. The
52.4 mmboe difference over production (683 mmboe in 2019)
mainly reflected volumes of natural gas consumed in operations
(45.4 mmboe), changes in inventory levels and other variations.
Approximately 66% of liquids production sold (325.4 mmbbl) was
destined to Eni's mid-downstream business. About 18% of natural
gas production sold (1,650 bcf) was destined to Eni's Gas &
Power segment.
Eni Annual Report 2019OPERATING REVIEW | EXPLORATION & PRODUCTION 38
Annual oil and natural gas production(a)(b)(c)
Consolidated subsidiaries
Italy
Rest of Europe
Croatia
Norway
United Kingdom
North Africa
Algeria
Libya
Tunisia
Egypt
Sub-Saharan Africa(d)
Angola
Congo
Ghana
Nigeria
Kazakhstan
Rest of Asia
China
Indonesia
Iraq
Pakistan
Turkmenistan
United Arab Emirates
Americas
Ecuador
Mexico
Trinidad & Tobago
United States
Australia and Oceania
Australia
Equity-accounted entities
Angola
Indonesia
Norway
Tunisia
Venezuela
)
l
b
b
m
m
(
s
d
i
u
q
i
L
19
8
8
61
23
37
1
27
91
37
22
9
23
36
32
1
10
3
18
20
2
1
17
1
1
295
2
27
1
1
31
s
a
g
l
a
r
u
t
a
N
)
f
c
b
(
2019
137
64
64
419
41
374
4
551
227
25
54
36
112
100
184
113
29
37
2
3
24
1
23
51
51
1,757
35
66
2
70
173
s
n
o
b
r
a
c
o
r
d
y
H
)
e
o
b
m
m
(
45
20
20
138
30
106
2
129
133
42
32
15
44
55
66
1
21
15
7
3
19
24
2
1
21
10
10
620
8
40
1
14
63
)
l
b
b
m
m
(
s
d
i
u
q
i
L
s
a
g
l
a
r
u
t
a
N
)
f
c
b
(
2018
22
41
33
8
56
24
31
1
28
89
41
24
5
19
35
28
1
1
10
2
14
19
4
15
1
1
319
1
1
3
5
155
162
4
88
70
474
38
431
5
445
185
31
55
7
92
97
202
137
14
39
10
2
43
13
30
42
42
1,805
32
2
81
115
s
n
o
b
r
a
c
o
r
d
y
H
)
e
o
b
m
m
(
50
71
1
49
21
144
31
111
2
110
123
46
34
7
36
52
65
1
26
13
7
4
14
27
4
2
21
8
8
650
7
1
18
26
)
l
b
b
m
m
(
s
d
i
u
q
i
L
s
a
g
l
a
r
u
t
a
N
)
f
c
b
(
2017
19
37
29
8
58
25
32
1
26
90
43
23
3
21
30
20
1
1
15
3
23
4
19
1
1
304
1
1
1
4
7
161
174
6
97
71
640
43
592
5
315
162
17
41
1
103
96
126
69
7
48
2
71
20
51
38
38
1,783
32
4
2
99
137
s
n
o
b
r
a
c
o
r
d
y
H
)
e
o
b
m
m
(
49
69
1
47
21
175
33
140
2
84
119
46
30
3
40
48
43
1
14
16
9
3
36
4
4
28
8
8
631
8
1
1
22
32
Total
326
1,930
683
324
1,920
676
311
1,920
663
(a) Includes Eni's share of equity-accounted equities.
(b) Includes volumes of hydrocarbons consumed in operations (45.4, 43.5 and 35.2 mmboe in 2019, 2018 and 2017, respectively).
(c) Effective January 1, 2019, Eni has updated the conversion rate of gas produced to 5,408 cubic feet of gas equals 1 barrel of oil (it was 5,458 cubic feet of gas per barrel in previous
reporting periods). This update reflected changes in Eni’s gas properties that took place in the last three years and was assessed by collecting data on the heating power of gas in Eni’s gas
fields currently on stream. The effect of this update on production expressed in boe was approximately 3 mmboe for the full year of 2019. Other per-boe indicators were only marginally
affected by the update (e.g. realized prices, costs per boe) and also negligible was the impact on depletion charges. Other oil companies may use different conversion rates.
(d) Cumulative daily production for the full year 2019 includes approximately 4 mmboe of volumes (mainly gas) as part of a long-term supply agreement to a state-owned national oil
company, whereby the buyer has paid the price without lifting the underlying volume due to the take-or-pay clause. Management has estimated to be highly probable that the buyer will
not redeem its contractual right to lift the pre-paid volumes within the contractual terms. The price collected on such volumes was recognized as revenue in the financial statements in
accordance to IFRS 15 because the Company has satisfied its performance obligation under the contract. In the Oil & Gas disclosures prepared on the basis of SFAS 69, this volume is
classified in the movements of the reserves as of 31.12.2019 as disposal and the related revenue is excluded from the results of exploration and production of hydrocarbons. The calculation
of the price indicators per boe and operating cost per boe is unaffected by this transaction.
OPERATING REVIEW | EXPLORATION & PRODUCTION
39
Daily oil and natural gas production(a)(b)(c)
Consolidated subsidiaries
Italy
Rest of Europe
Croatia
Norway
United Kingdom
North Africa
Algeria
Libya
Tunisia
Egypt
Sub-Saharan Africa(d)
Angola
Congo
Ghana
Nigeria
Kazakhstan
Rest of Asia
China
Indonesia
Iraq
Pakistan
Turkmenistan
United Arab Emirates
Americas
Ecuador
Mexico
Trinidad & Tobago
United States
Australia and Oceania
Australia
Equity-accounted entities
Angola
Indonesia
Norway
Tunisia
Venezuela
s
a
g
l
a
r
u
t
a
N
)
d
/
f
c
m
m
(
2019
376.4
174.6
174.6
1,149.2
111.8
1,025.8
11.6
1,509.0
621.2
67.3
147.7
97.9
308.3
272.4
502.7
308.1
78.7
101.2
6.0
8.7
66.8
2.8
64.0
139.6
139.6
4,811.9
97.3
182.4
3.4
192.0
475.1
s
d
i
u
q
i
L
)
d
/
l
b
b
k
(
53
23
23
166
62
101
3
75
249
102
59
24
64
100
86
1
2
27
7
49
55
6
4
45
2
2
809
4
74
3
3
84
s
n
o
b
r
a
c
o
r
d
y
H
)
d
/
e
o
b
k
(
123
55
55
379
83
291
5
354
363
113
87
42
121
150
179
1
59
41
19
8
51
68
6
4
58
28
28
1,699
23
108
3
38
172
s
d
i
u
q
i
L
)
d
/
l
b
b
k
(
s
a
g
l
a
r
u
t
a
N
)
d
/
f
c
m
m
(
2018
426.2
444.9
11.4
241.8
191.7
1,299.1
105.5
1,180.3
13.3
1,218.5
505.4
84.2
150.3
19.3
251.6
265.2
550.7
376.5
36.7
106.1
27.2
4.2
118.9
35.7
83.2
114.3
114.3
4,943.2
89.2
2.2
4.4
221.7
317.5
60
113
89
24
154
65
86
3
77
244
111
65
15
53
94
77
1
3
28
6
39
52
12
40
2
2
873
3
3
8
14
s
n
o
b
r
a
c
o
r
d
y
H
)
d
/
e
o
b
k
(
138
194
2
134
58
392
85
302
5
300
337
127
92
18
100
143
177
1
71
34
20
11
40
75
12
7
56
23
23
1,779
19
1
4
48
72
s
d
i
u
q
i
L
)
d
/
l
b
b
k
(
s
a
g
l
a
r
u
t
a
N
)
d
/
f
c
m
m
(
2017
441.6
476.4
16.9
265.4
194.1
1,753.0
117.2
1,623.1
12.7
862.7
444.3
45.9
112.6
2.7
283.1
263.7
345.9
0.1
188.8
19.6
131.5
5.9
194.0
55.4
138.6
105.0
105.0
4,886.6
89.0
11.0
4.1
270.5
374.6
53
102
81
21
158
68
87
3
72
247
119
63
8
57
83
53
2
3
40
8
63
12
51
2
2
833
3
1
3
12
19
s
n
o
b
r
a
c
o
r
d
y
H
)
d
/
e
o
b
k
(
134
189
3
129
57
479
90
384
5
230
327
126
83
9
109
132
116
2
38
43
24
9
99
12
10
77
22
22
1,728
20
3
4
61
88
Total
893
5,287.0
1,871
887
5,260.7
1,851
852
5,261.2
1,816
(a) Includes Eni's share of equity-accounted equities.
(b) Includes volumes of hydrocarbons consumed in operations (124, 119 and 97 kboe/d in 2019, 2018 and 2017, respectively).
(c) Effective January 1, 2019, the conversion rate of natural gas from cubic feet to boe has been updated to 1 barrel of oil = 5,408 cubic feet of gas (it was 1 barrel of oil = 5,458 cubic feet of gas).
The effect on production has been 9 kboe/d in the full year 2019.
(d) Cumulative daily production for the full year 2019 includes approximately 10 kboe/d respectively of volumes (mainly gas) as part of a long-term supply agreement to a state-owned
national oil company, whereby the buyer has paid the price without lifting the underlying volume due to the take-or-pay clause. Management has estimated to be highly probable that
the buyer will not redeem its contractual right to lift the pre-paid volumes within the contractual terms. The price collected on such volumes was recognized as revenue in the financial
statements in accordance to IFRS 15 because the Company has satisfied its performance obligation under the contract. In the Oil & Gas disclosures prepared on the basis of SFAS 69, this
volume is classified in the movements of the reserves as of 31.12.2019 as disposal and the related revenue is excluded from the results of exploration and production of hydrocarbons.
The calculation of the price indicators per boe and operating cost per boe is unaffected by this transaction.
Eni Annual Report 2019OPERATING REVIEW | EXPLORATION & PRODUCTION
40
PRODUCTIVE WELLS
In 2019, oil and gas productive wells were 8,292 (2,848.8 of which
represented Eni's share). In particular, oil productive wells were
6,710 (2,113.2 of which represented Eni's share); natural gas
productive wells amounted to 1,582 (735.6 of which represented
Eni's share). The following table shows the number of productive
wells in the year indicated by the Group and its equity-accounted
entities in accordance with the requirements of FASB Extractive
Activities - Oil and Gas (Topic 932).
Productive oil and gas wells(a)
Italy
Rest of Europe
North Africa
Egypt
Sub-Saharan Africa
Kazakhstan
Rest of Asia
Americas
Australia and Oceania
(units)
2019
Oil wells
Natural gas wells
Gross
204.0
657.0
589.0
1,196.0
2,620.0
204.0
990.0
250.0
Net
158.2
106.2
245.7
513.2
538.0
55.8
367.7
128.4
Gross
441.0
207.0
125.0
141.0
201.0
1
180.0
284.0
2.0
Net
383.0
67.0
67.5
43.6
27.0
0.3
63.6
81.6
2.0
6,710.0
2,113.2
1,582.0
735.6
(a) Includes 1,403 gross (382.8 net to Eni) multiple completion wells (more than one producing into the same well bore). Productive wells are producing wells and wells capable
of production. One or more completions in the same bore hole are counted as one well.
DRILLING ACTIVITIES
EXPLORATION
In 2019, a total of 31 new exploratory wells were drilled (16.3 of
which represented Eni's share), as compared to 24 exploratory
wells drilled in 2018 (15.6 of which represent Eni's share) and
25 exploratory wells drilled in 2017 (15.9 of which represented
Eni's share).
The following table shows the number of net productive, dry
Exploratory Well Activity
and in progress exploratory wells in the years indicated by the
Group and its equity-accounted entities in accordance with the
requirements of FASB Extractive Activities - Oil and Gas (Topic
932). The overall commercial success rate was 36% (47% net to
Eni) as compared to 62% (66% net to Eni) in 2018 and 60% (52%
net to Eni) in 2017.
Net wells completed (a)
2018
2017
Wells in progress at Dec. 31 (b)
2019
dry(c)
productive
dry (c)
gross
Italy
Rest of Europe
North Africa
Egypt
Sub-Saharan Africa
Kazakhstan
Rest of Asia
Americas
Australia and Oceania
2019
(units)
productive
0.3
0.5
4.5
0.5
5.8
productive
1.8
dry (c)
0.5
1.4
0.5
0.5
1.5
2.6
1.7
0.4
2.2
4.0
10.1
5.1
1.5
0.9
1.7
0.5
6.5
1.2
0.5
2.5
2.9
0.5
7.6
1.3
5.4
0.3
7.0
14.0
12.0
13.0
38.0
6.0
11.0
3.0
1.0
98.0
net
3.5
9.5
9.7
18.4
1.1
3.8
1.4
0.3
47.7
(a) Includes number of wells in Eni's share.
(b) Includes temporary suspended wells pending further evaluation.
(c) A dry well is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas sufficient quantities to justify completion as an oil or gas well.
OPERATING REVIEW | EXPLORATION & PRODUCTION
41
DEVELOPMENT
In 2019, a total of 241 development wells were drilled (85.4
of which represented Eni's share) as compared to 209
development wells drilled in 2018 (80.2 of which represented
Eni's share) and 178 development wells drilled in 2017 (90.7 of
which represented Eni's share).
The drilling of 84 development wells (21.0 of which represented Eni's
share) is currently underway.
The following table shows the number of net productive, dry and in
progress development wells in the years indicated by the Group and
its equity-accounted entities in accordance with the requirements of
FASB Extractive Activities - Oil and Gas (Topic 932).
Development Well Activity
2019
Net wells completed(a)
2018
2017
Well in progress at Dec. 31
2019
(units)
Italy
Rest of Europe
North Africa
Egypt
Sub-Saharan Africa
Kazakhstan
Rest of Asia
Americas
Australia and Oceania
productive
3.0
3.3
5.0
33.5
7.0
0.9
27.3
2.1
dry(b)
1.1
2.2
productive
3.0
2.8
9.6
30.7
7.3
0.9
21.9
2.3
0.8
dry(b)
0.3
0.5
0.1
productive
2.6
2.7
5.1
49.7
8.6
1.2
15.0
3.1
dry(b)
0.2
2.3
0.2
gross
2.0
25.0
2.0
9.0
19.0
1.0
25.0
1.0
net
1.6
2.2
1.1
3.5
3.4
0.3
7.9
1.0
(a) Includes number of wells in Eni's share.
(b) A dry well is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas sufficient quantities to justify completion as an oil or gas well.
82.1
3.3
79.3
0.9
88.0
2.7
84.0
21.0
ACREAGE
In 2019, Eni performed its operations in 41 Countries located
in five continents. As of December 31, 2019, Eni’s mineral right
portfolio consisted of 873 exclusive or shared rights of exploration
and development activities for a total acreage of 357,854 square
kilometers net to Eni (406,505 square kilometers net to Eni as
of December 31, 2018). Developed acreage was 29,283 square
kilometers and undeveloped acreage was 328,571 square
kilometers net to Eni.
In 2019, main changes derived from: (i) the entry in Bahrain and
new leases in the United Arab Emirates, Mozambique, Algeria,
Argentina, Egypt, Cyprus, Norway, Tunisia, Kazakhstan, Ivory Coast
and Mexico for a total acreage of approximately 33,500 square
kilometers; (ii) the total relinquishment of licenses mainly in India,
China, Vietnam, Portugal, Ecuador and the United Kingdom covering
an acreage of approximately 27,600 square kilometers; (iii) interest
increase mainly in Myanmar, Indonesia and the United States for
a total acreage of approximately 970 square kilometers; and (iv)
partial relinquishment in Indonesia, South Africa and Pakistan,
or interest reduction in Oman, Morocco, Cyprus, Indonesia and
Mozambique for approximately 55,500 square kilometers.
Eni Annual Report 2019OPERATING REVIEW | EXPLORATION & PRODUCTION
42
Oil and natural gas interests
December 31, 2018
December 31, 2019
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EUROPE
Italy
Rest of Europe
Cyprus
Greenland
Montenegro
Norway
Portugal
United Kingdom
Other Countries
AFRICA
North Africa
Algeria
Libya
Morocco
Tunisia
Egypt
Sub-Saharan Africa
Angola
Congo
Gabon
Ghana
Ivory Coast
Kenya
Mozambique
Nigeria
South Africa
Other Countries
ASIA
Kazakhstan
Rest of Asia
Bahrain
China
India
Indonesia
Iraq
Lebanon
Myanmar
Oman
Pakistan
Russia
Timor Leste
Turkmenistan
United Arab Emirates
Vietnam
Other Countries
AMERICAS
Ecuador
Mexico
United States
Venezuela
Other Countries
AUSTRALIA AND OCEANIA
Australia
46,332
14,987
31,345
17,111
1,909
614
2,628
3,182
4,018
1,883
165,699
33,932
1,155
13,294
17,925
1,558
5,248
126,519
5,303
1,471
4,107
579
2,905
43,948
978
7,722
26,202
33,304
181,414
1,543
179,871
5,228
5,244
23,769
446
1,461
13,558
77,146
5,786
17,975
1,230
180
1,472
23,132
3,244
9,303
1,985
3,000
2,191
1,066
1,061
3,757
3,757
309
128
181
7
2
1
131
38
2
260
69
47
11
1
10
56
135
45
25
4
3
5
6
10
32
1
4
69
8
61
1
6
13
1
2
4
1
12
2
4
1
9
4
1
229
10
205
6
8
6
6
15,282
9,545
5,737
4,828
909
54,351
17,628
12,157
1,963
3,508
5,659
31,064
8,349
1,430
226
21,059
12,686
2,391
10,295
77
2,605
1,074
3,390
200
2,949
2,299
14
1,024
1,261
728
728
58,616
7,595
51,021
26,614
4,890
1,228
14,577
1,011
2,701
273,494
51,716
279
24,673
23,900
2,864
15,710
206,068
7,841
1,320
4,107
1,127
4,921
50,677
25,304
8,631
55,677
46,463
267,851
5,124
262,727
2,858
20,898
3,653
24,080
90,760
8,370
53,930
2,612
17,058
23,908
14,600
17,763
5,455
1,683
1,543
9,082
2,860
2,860
73,898
17,140
56,758
26,614
4,890
1,228
19,405
1,920
2,701
327,845
69,344
12,436
26,636
23,900
6,372
21,369
237,132
16,190
2,750
4,107
1,353
4,921
50,677
25,304
29,690
55,677
46,463
280,537
7,515
273,022
2,858
77
23,503
1,074
3,653
24,080
90,760
11,760
53,930
2,612
200
20,007
23,908
14,600
20,062
5,469
2,707
2,804
9,082
3,588
3,588
9,278
7,887
1,391
777
614
15,194
7,966
5,472
958
1,536
2,113
5,115
1,073
843
100
3,099
3,199
442
2,757
13
1,029
446
872
180
217
1,024
14
513
497
588
588
28,750
5,845
22,905
14,557
1,909
614
3,436
506
1,883
148,431
23,907
100
12,336
10,755
716
5,500
119,024
2,671
628
4,107
479
3,724
43,948
4,349
3,543
22,271
33,304
139,497
1,718
137,779
2,858
14,926
1,461
14,147
49,918
2,907
17,975
1,620
10,170
18,553
3,244
9,679
3,092
1,422
569
4,596
2,214
2,214
38,028
13,732
24,296
14,557
1,909
614
4,213
1,120
1,883
163,625
31,873
5,572
13,294
10,755
2,252
7,613
124,139
3,744
1,471
4,107
579
3,724
43,948
4,349
6,642
22,271
33,304
142,696
2,160
140,536
2,858
13
15,955
446
1,461
14,147
49,918
3,779
17,975
1,620
180
10,387
18,553
3,244
10,703
3,106
1,935
1,066
4,596
2,802
2,802
Total
406,505
873
85,346
620,584
705,930
29,283
328,571
357,854
(a) Square kilometers.
(b) Developed acreage refers to those leases in which at least a portion of the area is in production or encompasses proved developed reserves.
OPERATING REVIEW | EXPLORATION & PRODUCTION
43
Main producing assets (Group share in %) and the year in which Eni started operations
ITALY
Operated
(1926)
Adriatic and Ionian Sea Barbara (100%), Cervia/Arianna (100%), Annamaria (100%), Clara NW (51%),
Luna (100%), Angela (100%), Hera Lacinia (100%) and Bonaccia (100%)
Basilicata Region
Val d'Agri (61%)
Sicily
Gela (100%), Tresauro (45%), Giaurone (100%), Fiumetto (100%),
Prezioso (100%) and Bronte (100%)
REST
OF EUROPE
Norway(a)
(1965)
Operated
Non-operated Åsgard (15.35% ), Kristin (13.31%), Heidrun (3.60%), Mikkel (33.67%), Tyrihans (12.54%),
Goliat (45.24%), Marulk (13.92%), Balder & Ringhorne (62.64%) and Ringhorne East (48.71%)
United Kingdom (1964)
Operated
Morvin (20.88%), Great Ekofisk Area (8.62%), Boyla (13.92%), Brage (8.53%) and Snorre (12.91%)
Liverpool Bay (100%) and Hewett Area (89.3%)
Non-operated Elgin/Franklin (21.87%), Glenelg (8%), J Block (33%), Jasmine (33%) and Jade (7%)
NORTH
AFRICA
Algeria(b)
(1981)
Operated
Sif Fatima II (49%), Zemlet El Arbi (49%), Ourhoud II (49%), Blocks 403a/d (from 65% to 100%),
Block ROM North (35%), Blocks 401a/402a (55%), Block 403 (50%) and Block 405b (75%)
Non-operated Block 404 (12.25%) and Block 208 (12.25%)
Libya(b)
(1959)
Non-operated Onshore contract
areas
Tunisia
(1961)
Operated
EGYPT(b)(c)
(1954)
Operated
Area A (former concession 82 - 50%), Area B (former concession 100/ Bu-
Attifel and Block NC 125 - 50%), Area E (El Feel - 33.3%) and Area D (Block
NC 169 - 50%)
Area C (Bouri - 50%) and Area D (Blocco NC 41 - 50%)
Offshore contract
areas
Maamoura (49%), Baraka (49%), Adam (25%), Oued Zar (50%), Djebel Grouz (50%), MLD (50%)
and El Borma (50%)
Shorouk (Zohr - 50%), Nile Delta (Abu Madi West/Nidoco - 75%), Sinai (Belayim Land, Belayim
Marine and Abu Rudeis - 100%), Meleiha (76%), North Port Said (Port Fouad - 100%), Temsah
(Tuna, Temsah and Denise - 50%), South West Meleiha (100%), Baltim (50%), Ras Qattara (El Faras
and Zarif - 75%), West Abu Gharadig (Raml - 45%), Ashrafi (50%) and West Razzak (100%)
SUB-SAHARAN
AFRICA
Non-operated Ras el Barr (Ha'py and Seth - 50%) and South Ghara (25%)
Angola
(1980)
Operated
Block 15/06 (36.84%)
Non-operated Block 0 (9.8%), Development Areas in the Block 3 and 3/05-A (12%), Development Areas in the
Congo
(1968)
Operated
Block 14 (20%), Development Area Lianzi in the Block 14 K/A IMI (10%) and Development Areas in
the Block 15 (18%)
Nené Marine (65%), Litchendjili (65%), Zatchi (55.25%), Loango (42.5%), Ikalou (100%), Djambala
(50%), Foukanda (58%), Mwafi (58%), Kitina (52%), Awa Paloukou (90%), M’Boundi (82%),
Kouakouala (74.25%), Zingali (100%) and Loufika (100%)
Non-operated Pointe-Noire Grand Fond (35%) and Likouala (35%)
Ghana
Nigeria
(2009)
Operated
Offshore Cape Three Points (44.44%)
(1962)
Operated
OMLs 60, 61, 62 and 63 (20%) and OML 125 (100%)
Non-operated(d) OML 118 (12.5%)
KAZAKHSTAN(b)
(1992)
Operated(e)
Karachaganak (29.25%)
Non-operated Kashagan (16.81%)
REST
OF ASIA
Indonesia
(2001)
Operated
Jangkrik (55%)
Iraq
(2009)
Operated(f)
Zubair (41.6%)
Pakistan
(2000)
Operated
Bhit/Bhadra (40%) and Kadanwari (18.42%)
Non-operated
Latif (33.3%), Zamzama (17.75%) and Sawan (23.7%)
Turkmenistan
(2008)
Operated
Burun (90%)
United Arab
Emirates
(2018)
Non-operated
Lower Zakum (5%) and Umm Shaif and Nasr (10%)
AMERICAS
Mexico
(2019)
Operated
Gulf of Mexico
Area 1 (100%)
United States
(1968)
Operated
Gulf of Mexico
Allegheny (100%), Appaloosa (100%), Pegasus (85%), Longhorn (75%),
Devils Towers (75%) and Triton (75%)
Alaska
Nikaitchuq (100%) and Oooguruk (100%)
Non-operated Gulf of Mexico
Texas
Europa (32%), Medusa (25%), Lucius (8.5%), K2 (13.4%), Frontrunner
(37.5%) and Heidelberg (12.5%)
Alliance area (27.5%)
Venezuela
(1998)
Non-operated
Perla (50%), Corocoro (26%) and JunÍn 5 (40%)
(a) Assets held by the Vår Energi equity-accounted entities (Eni's interest 69.6%).
(b) In certain extractive initiatives, Eni and the host Country agree to assign the operatorship of a given initiative to an incorporated joint venture, a so-called operating company.
The operating company in its capacity as the operator is responsible of managing extractive operations. Those operating companies are not controlled by Eni.
(c) Eni’s working interests (and not participating interests) are reported. This include Eni’s share of costs incurred on behalf of the first party accordingly to the terms of PSAs inforce in the
Country.
(d) As partners of SPDC JV, Eni holds a 5% interest in 17 onshore blocks and in 1 conventional offshore block and with a 12.86% in 2 conventional offshore blocks.
(e) Eni and Shell are co-operators.
(f) Eni is leading a consortium of partners including international companies and the national oil company Missan Oil.
Eni Annual Report 2019OPERATING REVIEW | EXPLORATION & PRODUCTION
44
MAIN EXPLORATION AND DEVELOPMENT PROJECTS
Eni’s exploration and production activities are conducted in many
Countries and are therefore subject to a broad range of legislation
and regulations. These cover virtually all aspects of exploration
and production activities, including matters such as license
acquisition, production rates, royalties, pricing, environmental
protection, export, taxes and foreign exchange. The terms and
condition of the leases, licenses and contracts under which
these Oil & Gas interests are held vary from Country to Country.
These leases, licenses and contracts are generally granted by
or entered into with a government entity or State company and
are sometimes entered into with private property owners. These
contractual arrangements usually take the form of concession
agreements or production sharing agreements:
Concessions contracts. Eni operates under concession contracts
mainly in OECD Countries. Concessions contracts regulate
relationships between States and oil companies with regards
to hydrocarbon exploration and production activity. Contractual
clauses governing mineral concessions, licenses and exploration
permits regulate the access of Eni to hydrocarbon reserves.
The company holding the mining concession has an exclusive
right on exploration, development and production activities,
sustaining all the operational risks and costs related to the
exploration and development activities, and it is entitled to the
productions realized. As a compensation for mineral concessions,
pays royalties on production (which may be in cash or in-kind)
and taxes on oil revenues to the State in accordance with local
tax legislation. Both exploration and production licenses are
granted generally for a specified period of time (except for
production licenses in the United States which remain in effect
until production ceases): the term of Eni’s licenses and the extent
to which these licenses may be renewed vary by area. Proved
reserves to which Eni is entitled are determined by applying Eni’s
share of production to total proved reserves of the contractual
area, in respect of the duration of the relevant mineral right.
Production Sharing Agreement (PSA). Eni operates under PSA
in several of the foreign jurisdictions mainly in African, Middle
Eastern, Far Eastern Countries. The mineral right is awarded to
the national oil company jointly with the foreign oil company that
has an exclusive right to perform exploration, development and
production activities and can enter into agreements with other
local or international entities. In this type of contract, the national
oil company assigns to the international contractor the task
of performing exploration and production with the contractor’s
equipment (technologies) and financial resources. Exploration
risks are borne by the contractor and production is divided into
two portions: “Cost Oil” is used to recover costs borne by the
contractor and “Profit Oil” is divided between the contractor
and the national company according to variable schemes and
represents the profit deriving from exploration and production.
Further terms and conditions of these contracts may vary from
Country to Country. Pursuant to these contracts, Eni is entitled
to a portion of a field’s reserves, the sale of which is intended
to cover expenditures incurred by the Company to develop
and operate the field. The Company’s share of production
volumes and reserves representing the Profit Oil includes the
share of hydrocarbons which corresponds to the taxes to be
paid, according to the contractual agreement, by the national
government on behalf of the Company. As a consequence, the
Company has to recognize at the same time an increase in the
taxable profit, through the increase of the revenues, and a tax
expense. Proved reserves to which Eni is entitled under PSAs
are calculated so that the sale of production entitlements should
cover expenses incurred by the Group to develop a field (Cost Oil)
and recognize the Profit Oil set contractually (Profit Oil). A similar
scheme applies to some service contracts.
ITALY
Development activities in the Adriatic offshore concerned: (i)
maintenance and production optimization; and (ii) efficiency
initiatives aimed at further emissions reduction. In particular,
the replacement of gas compression facilities was started at
the Rubicone Plant. In addition, within the VIII Agreement with
the Municipality of Ravenna, activities progressed with: (i)
territorial enhancement projects in collaboration with the Bologna
University; (ii) initiatives to support youth employment; (iii)
environmental protection projects at the coastline areas; and (iv)
school-work alternation projects.
During the year, digital transformation project was completed at
the Viggiano Oil Center in the Val d'Agri concession (Eni operator
with a 61%) improving asset integrity and environmental safety
as well as operational performance. In addition, the Energy Valley
project was launched and includes a number of initiatives relating
to environmental protection, projects to develop the area and
business sustainability: (i) Mini Blue Water project on circular
economy, for treatment, recover and reuse of water production at
the Val d'Agri Oil Center as well as installation of photovoltaic plants
supporting oil production facilities; (ii) ongoing environmental
and biodiversity monitoring projects. In particular the activity was
completed at the Center of Environmental Monitoring to manage
and spread data collected; and (iii) initiatives to support the agro-
food sector in the area also by means of training programs. In
particular, the activities of the year concerned upgrading of certain
areas and renovation of buildings for the agriculture sector also
with positive impact on local employment.
Following the Memorandum of Understanding for the Gela
area, signed with the Ministry of Economic Development in
November 2014, progressed: (i) development activities of Argo
and Cassiopea offshore gas fields (Eni’s interest 60%). The
project, through a significant reduction of the environmental
impact, expects to achieve the carbon neutrality target. The
activities provides the transportation of natural gas produced by
offshore wells through a pipeline to a new onshore treatment and
compression plant, that will be realized in certain reclaimed area
of the Gela Refinery. In addition, in 2019, Eni and the Ministry
of Environment signed a Memorandum of Understanding to
define initiatives, which will be implemented in the next years, to
renovate certain productive areas, environmental
remediation as well as innovative CCUS (carbon capture
utilization and storage) projects developed by Eni's proprietary
technologies; and (ii) school-work alternation projects, programs
to reduce school drop-out and university scholarship.
OPERATING REVIEW | EXPLORATION & PRODUCTION 45
NORTH AFRICA
Algeria In February 2019, Eni completed the acquisition of the
49% interest in the Sif Fatima II, Zemlet El Arbi and Ourhoud II
concessions in the Berkine Nord area, following the agreements
signed in 2018. The ongoing activities concerned: (i) the
fast-track development activity of the three concessions. In
particular, during the year, oil production start-up was achieved
by means of 7 production wells and the connection to the
existing facilities of the BRN area in the Block 403 (Eni’s interest
50%). In the first months of 2020, gas production started up with
the drilling of 2 wells and the connection of 2 additional wells
to the existing facilities, following the completion of the pipeline
from BRN to the MLE treatment plant in the Block 405b (Eni
operator with a 75% interest); and (ii) exploration and delineation
activities in the area. In particular, in 2019 exploration activity
yielded positive results with an oil and gas discovery in the
Ourhoud II concession. Development activities in other blocks
included: (i) production optimization in the operated Blocks
403a/d and ROM Nord (Eni’s interest 35%), Blocks 401a/402a
(Eni’s interest 55%), Block 405b, Block 403 and Block 404 (Eni’s
interest 12.25%); and (ii) the ongoing development activities of
the El Merk field in the Block 208 (Eni’s interest 12.25%) with the
drilling of production and water injection wells.
EGYPT
Exploration activity yielded positive results with: (i) a gas
discovery in the El Qar’a exploration license (Eni’s interest 75%),
located in the Nile Delta; (ii) the Sidri oil discovery in the Abu
Rudeis development lease (Eni’s interest 100%), in the Gulf of
Suez. Drilling activity has been completed and production wells
connected to the existing facilities; (iii) the Basma and Shemy oil
discoveries in the Meleiha development lease (Eni’s interest 76%).
Drilling activity has been completed at the Basma discovery and
related production wells connected to the existing facilities; (iv)
the SWM-A-3X gas and condensates discovery in the South West
Meleiha concession (Eni’s interest 100%); and (v) the Nour-1 gas
well in the Nour exploration license (Eni’s interest 40%).
The new discoveries confirm the positive track-record of Eni’s
exploration in the Country due to the continuous technological
progress in the exploration activities that allows to re-evaluate the
residual mineral potential in mature production areas.
In February 2019, Eni was awarded two onshore exploration blocks:
(i) a 100% interest in the South East Siwa block in the Western
Desert nearby to the South West Meleiha concession; and (ii) the
operatorship with a 50% interest in the West Sherbean block in the
onshore Nile Delta nearby to the operated Nooros producing fields
(Eni's interest 75%). In case of exploration success, the development
activities will benefit from the existing facilities.
In 2019 development activities were completed: (i) at the
Nooros field with the installation of a new gas pipeline to the El
Gamil treatment plant to production optimization and reserves’
recovery maximization; (ii) at the Baltim South West offshore
project (Eni operator with a 50% interest) with production
start-up. Development activities concerned the installation of a
production platform and the pipeline to the Abu Madi treatment
plant. The start-up was achieved just 19 months from the
FID confirming the success of Eni's strategy in a fast-track
approach to develop and start-up projects; and (iii) at the South
West Meleiha production area with the installation of a pipeline
connecting to the Meleiha operated treatment plant.
Development activities to ramp-up production at the Zohr field
(Eni operator with a 50% interest) concerned: (i) the completion
of the remaining three treatment units reaching a total of eight
units; (ii) the drilling and production start-up of additional four
wells; and (iii) the completion and entry into operation of a
second gas pipeline which increased installed capacity to more
than 3.2 bcf/d.
As of December 31, 2019, the aggregate development costs incurred
by Eni for the Zohr project and capitalized in the financial statements
amounted to $5.4 billion (€4.8 billion at the EUR/USD exchange
rate of December 31, 2019). Development expenditure incurred in
the year were €1.1 billion. As of December 31, 2019, Eni’s proved
reserves booked for the Zohr field amounted to 807 mmboe.
Development activities at other Eni's fields in Egypt concerned
infilling activities and production optimization in: (i) the Sinai
concession (Eni operator with an 100% interest), including the
production start-up achieved at the recent discoveries as well as
water injection optimization to support reservoir pressure; and (ii)
the operated Meleiha, Meleiha Deep (Eni's interest 100%) and Ras
Qattara (Eni's interest 75%) concessions in the Western Desert.
Within the social responsibility initiatives, the programs defined
by the Memorandum of Understanding signed in 2017 are
currently to be implemented. The agreement, which supports
the development activities of the Zohr project, defines two
intervention projects to be implemented in four years. The first,
already completed, included the renovation of the El Garabaa
hospital, located nearby the onshore Zohr production facilities and
the supply of necessary medical equipment. The second project,
for an overall expense of $20 million, includes certain socio-
economic and health programs to support local communities
in the Zohr and Port Said areas. The program defined with the
stakeholders and the local Authorities three main areas: (i)
aquaculture and fisheries; (ii) health care projects. In particular,
during 2019 Primary Health Care Center was completed and
provides health services to approximately 20,000 people. In
addition, the project includes also further initiatives of health
training and prevention; and (iii) programs to support youth.
In particular, in 2019, the construction of a youth center was
completed.
SUB-SAHARAN AFRICA
Angola Exploration activities yielded positive results with the
Agogo oil discovery and the Agogo-2 and Agogo-3 appraisal
wells, then with the Ndungu and the Agidibo oil wells in the
operated Block 15/06 (Eni’s interest 36.84%), which including
the discoveries of the end of 2018 (Kalimba and Afoxè) have
increased the block’s additional mineral potential to 2 billion
barrels of oil in place. In 2020 production start-up was achieved at
the Agogo field with the connection to Ngoma FPSO, as part of the
West Hub project.
In particular, the production start-up was achieved by means of
the application of digital technologies that allowed to optimize
time in the drilling phase. The record start-up, in nine months from
discovery, confirms Eni’s commitment of the fast-track model
Eni Annual Report 2019OPERATING REVIEW | EXPLORATION & PRODUCTION 46
in the development of its discoveries leveraging on the existing
facilities to maximize projects value. Within the development of
the Block 15/06 the activities are ongoing in order to make the
East Hub as the first Eni offshore plant fully digitalized.
In January 2020, Eni was awarded a 60% interest in the Block 28
as operator. The development of the discoveries will leverage on
the synergies with the existing production facilities.
In October 2019 Eni, as operator of a new joint venture (Eni's
interest 25.6%), signed a commercial agreement with the partners
of the Angola LNG (Eni's interest 13.6%) for the development of the
gas fields to support the liquefaction plant. The first development
project is expected to be sanctioned in 2020.
In November 2019, Eni and the Country's Autorithy signed
a Memorandum of Understanding (MoU). The agreement
confirms Eni's strategy that combines traditional business
with a commitment to diversified and sustainable growth in the
territories in which Eni operates. In particular, the MoU includes:
(i) projects for access to energy, economic diversification,
access to water and health services, education and training. The
projects will be developed in the Cabinda area, in the northern
part of the Country; (ii) the construction of a photovoltaic plant
in the Namibe area. Eni and the Authorities already signed the
concession agreement; (iii) projects to strengthen specialist
health services as defined by the MOU signed with the Ministry
of Health. The projects will be carried out at the health structures
of Luanda and Cabinda area; and (iv) the acquisition of the
offshore Block 1/14 (Eni operator with a 35% interest) and the
onshore Cabinda Center block (Eni's interest 42.5%).
In 2019 Eni finalized an extension of exploitation rights until 2032
of Block 15 (Eni's interest 20%), the number of the Development
Areas has been reduced, joining some of them together.
Development activities concerned: (i) the completion of the
planned activities at the Vandumbu field in the West Hub project
in the operated Block 15/06; and (ii) production optimization at
the Mpungi and Sangos fields in the Block 15/06 and in some
fields in the Block 0 (Eni's interest 9.8%).
Eni also continues its commitment to support socio-economic
development in the southern region of the Country, in Huila
and Namibe area. During 2019 activities progressed with the
completion of projects for access to energy from renewable
sources and to drinking water.
Mozambique In May 2019, Eni and ExxonMobil signed a farm-in
agreement for the purchase of a 10% interest of the A5-B, Z5-C
and Z5-D offshore blocks, in the deep waters of the Angoche and
Zambesi basins.
In July 2019, Eni divested a 25.5% interest of the offshore
A5-A block, located in the deep waters of the Zambesi, to
Qatar Petroleum. Following this acquisition Eni retains the
operatorship with a 34% interest.
The development activities of Area 4 offshore (Eni’s interest
25%) concerned the Coral South project, operated by Eni, and
the discoveries of Mamba Complex where Eni is expected to
coordinate the upstream development and production phase
and ExxonMobil the construction and operation phase of natural
gas liquefaction facilities onshore.
The sanctioned Coral South project includes the construction of
FPSO for the gas treatment, liquefaction, storage and export of
LNG, with a capacity of approximately 3.4 mmtonnes/y, fed by 6
subsea wells. Production start-up is expected in 2022. The LNG
produced will be sold by the Area 4 concessionaires to BP under a
long-term contract for a period of twenty years, with an option for
an additional ten-year term.
Within the Mamba Complex discoveries, the Rovuma LNG project
provides for the development of the straddling reserves of Area 1
according to its independent industrial plan, coordinated with the
operator of Area 1 (Total). The development project will include
also a part of non-straddling reserves. In 2019, the Mozambique
authorities approved the unitization agreement between the Area
1 and Area 4. The project provides the construction of two onshore
LNG trains with capacity of approximately 7.6 mmtonnes/y each,
feed by 24 subsea wells, the gas treatment, the liquefaction,
the storage and the export of LNG. In May 2019, the plan of
development (POD) was approved by the relevant Authorities.
In 2019, Eni’s programs to support the local communities of the
Country progressed with: (i) the scholarship programs mainly
in Pemba, also by means of ordinary and extraordinary schools
maintenance activities and training initiatives; (ii) initiatives
to promote more sustainable domestic behaviors through clean
cooking projects; (iii) biodiversity protection programs also
through agreements with institutions and Authorities of the
Country; (iv) projects for the protection and conservation of
forests (REDD + program) in collaboration with the Government
of Mozambique; and (v) health care initiatives, coordinated with
the Country’s health Authorities, in the Maputo area, by means of
specific initiatives on prevention.
Nigeria In December 2019, the FID was sanctioned for the
construction of the seventh treatment unit of the Bonny
liquefaction plant (Eni's interest 10.4%). The additional
treatment unit will increase the production capacity from 22
mmtonnes/y of LNG, corresponding to approximately 1,236
bcf/y of gas feed, to over 30 mmtonnes/y. Development activity
is expected to be completed in 2024 with production start-up.
Natural gas supplies to the plant are currently provided under
a gas supply agreements from the SPDC JV (Eni’s interest 5%),
TEPNG JV and the NAOC JV (Eni’s interest 20%). In 2019, the
Bonny liquefaction plant processed approximately 1,165 bcf. LNG
production is sold under long-term contracts and exported to the
Asian and European markets by the Bonny Gas Transport fleet,
wholly owned by Nigeria LNG Ltd.
Development activities of the OMLs 60, 61, 62 and 63 blocks (Eni
operator with a 20% interest) concerned: (i) the completion of
planned activities and production start-up of the Obiafu 41 gas and
condensates discovery; and (ii) increasing generation capacity of
the combined cycle power plant at Okpai to achieve about 1 GW.
Natural gas production of the area will support the plant capacity.
Other development activities concerned: (i) infilling program
and production optimization in the OML 118 block (Eni’s interest
12.5%); (ii) the completion of drilling activities of two additional
oil wells at the Abo field in the operated OML 125 block (Eni’s
interest 100%). Peak production of 26 kbbl/d has been achieved
during the year; (iii) the completion of the associated gas project
in the OML 43 block (Eni’s interest 5%) and the SSAGS project in
OPERATING REVIEW | EXPLORATION & PRODUCTION 47
the OML 28 block (Eni’s interest 5%). Associated gas production
will be sold in the domestic market; and (iv) the flaring down
Assa North project (Eni’s interest 5%) has been sanctioned to
support the domestic market.
Eni continues the collaboration with the Food and Agriculture
Organization (FAO) to foster access to safe and clean water in
Nigeria, mainly in the north-east areas, by drilling boreholes powered
with photovoltaic systems, both for domestic use and irrigation
purposes. In 2019 Eni realized 6 wells achieving a total of 16 wells,
which including the other wells completed in 2018. Eni’s programs
to support local communities progressed with: (i) access to energy
initiatives; (ii) economic programs for diversification purposes, in
particular with the Green River Project; (iii) professional training and
scholarship programs; and (iv) renovation and construction of health
centers and supply of medical equipment.
KAZAKHSTAN
Kashagan The development activities of the Kashagan field (Eni’s
interest 16.81%) envisage for increasing the production capacity
up to 450 kbbl/d by upgrading the existing gas compression
capacity, the conversion of production wells into injection wells, the
debottlenecking and the revamping of existing facilities with the
construction of a new onshore gas treatment plant.
As of December 31, 2019, the aggregate costs incurred by Eni for the
Kashagan project capitalized in the financial statements amounted
to $10 billion (€8.9 billion at the EUR/USD exchange rate of December
31, 2019). This capitalized amount included: (i) $7.4 billion relating
to expenditure incurred by Eni for the development of the oil field;
and (ii) $2.6 billion relating primarily to accrued finance charges
and expenditures for the acquisition of interests in the Consortium
from exiting partners upon exercise of pre-emption rights in previous
years. Cost incurred in the year were €106 million.
As of December 31, 2019, Eni’s proved reserves booked for the
Kashagan field amounted to 661 mmboe, increased from 2018.
Karachaganak Within the gas treatment expansion projects of the
Karachaganak field (Eni’s interest 29.25%), activities concerned: (i)
the Karachaganak Debottlenecking project progressed; (ii) project
of the construction of fourth gas re-injection unit was sanctioned
and activity started up during the year; and (iii) the Front End
Engineering Design of the Karachaganak Expansion Project has
been completed. The planned activities include the installation of
two additional gas re-injection facility.
Eni continues its commitment to support local communities in
the nearby area of the Karachaganak field. In particular, activities
focused on: (i) professional training; and (ii) realization of
kindergartens and schools, maintenance of bridges and roads,
construction of sport centers.
As of December 31, 2019, the aggregate costs incurred by Eni for
the Karachaganak project capitalized in the financial statements
amounted to $4.1 billion (€3.7 billion at the EUR/USD exchange rate
of December 31, 2019). Cost incurred in the year were €267 million.
As of December 31, 2019, Eni’s proved reserves booked for the
Karachaganak field amounted to 448 mmboe, slightly decreased
from 2018, mainly due to changes of Brent price.
REST OF ASIA
United Arab Emirates In 2019, Eni awarded: (i) the operatorship
of the Block 1 and 2 with a 70% interest, located offshore Abu
Dhabi. The exploration commitment for the first phase consists
in exploration studies for the Block 1 and the drilling of two
exploration wells and one appraisal well in the Block 2; (ii) three
onshore exploration concessions in the Emirate of Sharjah with a
75% interest in the operated concession Area A and C and a 50%
interest in the participated concession Area B. In January 2020,
exploration activities yielded positive results with the Mahani-1
gas and condensates discovery in the Area B concession; and
(iii) the operatorship with a 90% interest in the Block A, located
offshore Emirate of Ras al Khaimah.
Development activities concerned: (i) the Dalma Gas Development
project in the Gasha concession (Eni’s interest 25%). The final
investment decision was sanctioned. Start-up is expected in 2022;
and (ii) the Nasr Full Field Development project in the Umm Shaif/
Nasr concession (Eni’s interest 10%). The program was completed
and production ramp-up achieved in the year.
AMERICAS
Mexico In February 2020, exploration activities yielded positive
results with the Saasken offshore oil discovery in the operated
Block 10 (Eni’s interest 65%).
In 2019 production start-up was achieved at the operated Area 1
license (Eni’s interest 100%) by means of the drilling of two wells
and the installation of a production platform which is linked by a
sealine to an onshore treatment unit. The drilling activities have
been supported by means of digital tools to optimize the timing.
The full field development envisages a phased installation of three
additional platforms and a FPSO unit, which will increase the
production capacity up to 100 kbbl/d in 2021.
In 2019, Eni and local Authorities signed a cooperation agreement
to identify local development programs relating to education,
health and environment as well as economic diversification
initiatives to support employment. In particular, as defined by
the agreements, during the year the activities concerned: (i) the
rehabilitation activities of two schools have started. The program
includes initiatives of renovation for 13 schools as well as training
programs; (ii) the launch of fight campaigns child malnutrition;
(iii) feasibility studies with local Universities to identify certain
economic diversification projects; and (iv) has been finalized,
with the support of the Danish Institute for Human Rights, an
impact assessment for the elaboration of an action plan in the
field of human rights.
Eni Annual Report 2019OPERATING REVIEW | EXPLORATION & PRODUCTION 48
CAPITAL EXPENDITURE
Capital expenditure of the Exploration & Production segment
(€6,996 million) concerned mainly development of oil and
gas reserves (€5,931 million) directed mainly outside Italy, in
particular in Egypt, Nigeria, Kazakhstan, Indonesia, Mexico, the
United States and Angola.
Development expenditure in Italy mainly concerned sidetrack
and workover activities in mature fields. Acquisition of proved
and unproved properties (€400 million) concerned mainly the
acquisition of reserves in Alaska e in Algeria.
Exploration expenditure (€586 million) concerned mainly Egypt,
Angola, Mexico, the United Arab Emirates and Libya.
In 2019 overall expenditure in R&D amounted to €71 million (€96
million in 2018). A total of 12 new patents applications were filed.
Acquisition of proved and unproved properties
Egypt
North Africa
Sub-Saharan Africa
Rest of Asia
Americas
Exploration
Italy
Rest of Europe
North Africa
Egypt
Sub-Saharan Africa
Kazakhstan
Rest of Asia
Americas
Australia and Oceania
Development
Italy
Rest of Europe
North Africa
Egypt
Sub-Saharan Africa
Kazakhstan
Rest of Asia
Americas
Australia and Oceania
Other expenditure
TOTAL CAPITAL EXPENDITURE
(€ million)
2019
400
1
135
23
241
586
43
71
86
128
7
141
74
36
5,931
289
110
536
1,481
1,406
371
1,028
695
15
79
6,996
2018
869
2017
5
869
463
1
52
20
80
22
140
146
2
6,506
380
600
525
2,205
1,635
193
550
381
37
63
7,901
5
442
5
186
55
70
25
3
20
76
2
7,236
260
399
626
3,030
1,852
197
666
195
11
56
7,739
Change
(469)
1
135
(846)
241
123
(1)
(9)
51
6
106
7
1
(72)
34
(575)
(91)
(490)
11
(724)
(229)
178
478
314
(22)
16
(905)
OPERATING REVIEW | EXPLORATION & PRODUCTION
Gas
& Power
49
KEY PERFORMANCE INDICATORS
2019
2018
2017
(total recordable injuries/worked hours) x 1,000,000
TRIR (Total Recordable Injury Rate)
of which: employees
contractors
Sales from operations(a)
Operating profit (loss)
Adjusted operating profit (loss)
of which: Gas & LNG Marketing and Power
Eni gas e luce
Adjusted net profit (loss)
Capital expenditure
Worldwide gas sales
of which: in Italy
outside Italy
LNG sales(b)
Retail customers in Italy
Electricity produced
Electricity sold
Employees at year end
of which: outside Italy
Direct GHG emissions
GHG emissions/Equivalent produced electricity (Eni Power)
0.59
0.46
0.84
50,015
699
654
376
278
426
230
73.07
37.85
35.22
10.1
7.74
21.66
39.49
3,015
975
10.47
394
0.56
0.34
0.99
55,690
629
543
342
201
310
215
76.71
39.03
37.68
10.3
7.74
21.62
37.07
3,040
951
11.08
402
0.37
0.45
0.23
50,623
75
214
77
137
52
142
80.83
37.43
43.40
8.3
7.65
22.42
35.33
4,313
2,031
11.30
395
(€ million)
(bcm)
(million)
(TWh)
(number)
(mmtonnes CO2eq)
(gCO2eq/kWheq)
(a) Before elimination of intragroup sales.
(b) Refers to LNG sales of the Gas & Power segment (included in worldwide gas sales).
Performance of the year
˛ In 2019, the total recordable injury rate (TRIR) of the workforce
amounted to 0.59, representing a slight increase compared to 2018.
power plants reported higher consumption of refinery gas in place of
natural gas.
˛ In 2019 the greenhouse gas emissions (GHG) reported an
˛ In 2019, the Gas & Power segment reported an adjusted
improved performance, approximately a reduction of 5.5%, due to
lower power generation and gas transport.
˛ GHG emissions/ Equivalent produced electricity decreased by 2%
compared to a year earlier due to the circumstance that in 2018
operating profit of €654 million, up by 20% compared to 2018,
mainly due to optimization of gas and power assets portfolio in
Europe, which benefitted from a volatile scenario and a better
performance of the retail business thanks to the more effective
ANDAMENTO OPERATIVO | GAS & POWEREni Relazione Finanziaria Annuale 2019
50
commercial initiatives, higher extracommodity revenues and
lower opex.
˛ Eni worldwide gas sales amounted to 73.07 bcm, down by
˛ Power sales amounted to 39.49 TWh, recording an increase of
6.5% (up by 2.42 TWh) compared to 2018, mainly due to higher
volumes sold to the Italian free market.
3.64 bcm or 4.7% compared to 2018. Eni’s sales in Italy (37.85
bcm) decreased by 3% compared to 2018.
˛ Capital expenditure amounting to €230 million mainly concerned
the gas marketing activities and the power business.
Agreements for the supply and transportation of natural gas
In May 2019, Eni signed an agreement with the state-owned
company Sonatrach for the renewal of supply contracts to import
Algerian gas in Italy until 2027 (with two additional optional years).
In July 2019, Eni finalized the contract for the transport of Algerian
gas to Italy via the Tunisian onshore and offshore pipelines.
The contract signed, through the subsidiary Trans Tunisian Pipeline
Company (TTPC), provides for the exclusive right to operate the gas
pipeline on the whole transportation capacity for the next 10 years
and the commitment to support the necessary investments to
modernize the infrastructure.
Agreement for LNG supply with Nigeria LNG
Signed an agreement for ten-year supply of 1.5 million tons of
LNG with the Nigeria LNG Limited joint venture, which allows Eni
to add volumes to its global LNG portfolio for a total of 2.6 million
tons and to support growth in the main target markets.
Damietta liquefaction plant
Signed a number of agreements with the Arab Republic of Egypt
(ARE), the Egyptian General Petroleum Corporation (EGPC), the
Egyptian Natural Gas Holding Company (EGAS) and the Spanish
company Naturgy, in order to restart the Damietta liquefaction
plant in Egypt by June 2020. The agreements provide for
the amicable resolution of the pending disputes of Union
Fenosa Gas with EGAS and ARE, and the subsequent corporate
restructuring of Union Fenosa Gas, whose 80% participation in
the Damietta plant will be transferred to Eni (50%) and to EGAS
(30%). Eni will also take over the contract for the purchase
of natural gas for the plant and will receive corresponding
liquefaction rights, thus increasing the volumes of LNG in its
portfolio by 3.78 billion cubic meters per year. Eni will take over
the commercial activities of natural gas in Spain from Unión
Fenosa Gas, strengthening its presence in the European gas
market. The effectiveness of the agreements is subordinated to
the occurrence of certain conditions precedent.
Development of the retail portfolio in the distributed generation from renewable sources
In November 2019, Eni, through the subsidiary Eni gas e luce,
completed the acquisition of 70% of Evolvere SpA, a company
leader in sale, installation and maintenance of photovoltaic
systems and storage systems for residential and business
customers. The acquisition has been finalized in January 2020.
Leveraging on this operation, Eni will be a market leader in
power generation from renewable sources in Italy.
Charging solutions for electric mobility
As part of its strategy for sustainable mobility business, Eni,
through the subsidiary Eni gas e luce, has launched the E-start
HUB service which offers complete charging solutions for electric
mobility in the residential and business sectors, from project
development to installation, maintenance and digital services.
OPERATING REVIEW | GAS & POWER 51
Digital transformation initiatives
The planned initiatives of digital transformation mainly concern
the acquisition, management and support of customers, energy
management and digitalization of the support functions. Projects of
digital transformation are currently under way aimed at the digital
evolution of the methods of interaction with the customer base
(current and potential) and the enhancement of the information
assets in terms of new data sources (Big data & Advanced Analytics)
in order to prevent churn, promote dedicated commercial offers and
risk management.
NATURAL GAS
Eni operates in a liberalized market where energy customers are
allowed to choose the gas supplier and, according to their specific
needs, to evaluate the quality of services and offers. Overall Eni
supplies 9.4 million retail clients (gas and electricity) in Italy and
Europe. In particular, clients located all over Italy are 7.7 million. In
a trading environment characterized by a slight increasing demand
(approximately up by 2% in the Italian market compared to the
previous year and up by 3% in the European Union, mainly leveraging
on power sector thanks to the competitive gas prices in Italy and
Europe, both) leveraging on power segment thanks to a competitive
structure of gas prices in Europe and Italy and characterized
by a raised competitive pressure, Eni carried out a number of
initiatives, – such as renegotiation of supply contracts, efficiency
and optimization actions – in order to consolidate the business
profitability in a weak demand scenario (for further information on
the European scenario, see chapter on “Risk factors” below).
approximately 92% of total supplies, decreased by 3.61 bcm or by
5.2% from the full year 2018. This mainly reflected lower volumes
purchased in Algeria (down by 5.36 bcm), in Russia (down by 1.53
bcm), in Indonesia (down by 1.48 bcm), partly offset by higher
purchases in France (up by 2.90 bcm), Libya (up by 1.31 bcm) and
in the United States of America (up by 1.20 bcm). Supplies in Italy
(5.44 bcm) increased by 2.1% from the full year 2018.
SUPPLIES OF ENI’S CONSOLIDATED SUBSIDIARIES
8%
25%
70.65 bcm
35%
Italy
Russia
Algeria
Libya
The Netherlands
Norway
Others
SUPPLY OF NATURAL GAS
In 2019, Eni’s consolidated subsidiaries supplied 70.65 bcm of
natural gas, down by 3.50 bcm or by 4.7% from the full year 2018.
Gas volumes supplied outside Italy from consolidated subsidiaries
(65.21 bcm), imported in Italy or sold outside Italy, represented
9%
6%
8%
9%
Supply of natural gas
Italy
Russia
Algeria (including LNG)
Libya
Netherlands
Norway
United Kingdom
Indonesia (LNG)
Qatar (LNG)
Other supplies of natural gas
Other supplies of LNG
OUTSIDE ITALY
TOTAL SUPPLIES OF ENI'S CONSOLIDATED SUBSIDIARIES
Offtake from (input to) storage
Network losses, measurement differences and other changes
AVAILABLE FOR SALE BY ENI'S CONSOLIDATED SUBSIDIARIES
Available for sale by Eni's affiliates
TOTAL AVAILABLE FOR SALE
(bcm)
2019
5.44
24.71
6.66
5.86
4.12
6.43
1.75
1.58
2.79
7.91
3.40
65.21
70.65
0.08
(0.22)
70.51
2.56
73.07
2018
5.33
26.24
12.02
4.55
3.95
6.75
2.21
3.06
2.56
5.52
1.96
68.82
74.15
0.08
(0.18)
74.05
2.66
76.71
2017
5.05
28.09
13.18
4.76
5.20
7.48
2.36
0.74
2.36
6.75
2.31
73.23
78.28
0.31
(0.45)
78.14
2.69
80.83
Change
0.11
(1.53)
(5.36)
1.31
0.17
(0.32)
(0.46)
(1.48)
0.23
2.39
1.44
(3.61)
(3.50)
(0.04)
(3.54)
(0.10)
(3.64)
% Ch.
2.1
(5.8)
(44.6)
28.8
4.3
(4.7)
(20.8)
(48.4)
9.0
43.3
73.5
(5.2)
(4.7)
(22.2)
(4.8)
(3.8)
(4.7)
OPERATING REVIEW | GAS & POWEREni Annual Report 2019
52
In 2019, main gas volumes from equity production derived from:
(i) Italian gas fields (3.4 bcm); (ii) certain Eni fields located in
the British and Norwegian sections of the North Sea (2.3 bcm);
(iii) Libyan fields (1.8 bcm); (iv) Indonesia (0.8 bcm); and (v)
the United States (0.2 bcm). Supplied gas volumes from equity
production were approximately 8.5 bcm representing around 12% of
total volumes available for sale.
The available for sale by Eni’s affiliates amounted to 2.56 bcm (down
by 3.8% compared to 2018) and mainly referred to supplied volumes
from Oman, Spain, the United States and Nigeria.
SALES OF NATURAL GAS
In a 2019 scenario characterized by a raising competitive
pressure, natural gas sales amounted to 73.07 bcm (including
Eni’s own consumption, Eni’s share of sales made by equity-
accounted entities), down by 3.64 bcm or 4.7% from the
previous year.
Gas sales by entity
Total sales of subsidiaries
Italy (including own consumption)
Rest of Europe
Outside Europe
Total sales of Eni's affiliates (net to Eni)
Rest of Europe
Outside Europe
WORLDWIDE GAS SALES
Sales in Italy (37.85 bcm) decreased by 3% from the full
year 2018 mainly driven by lower sales to wholesalers, hub
and residential segments, partly offset by higher sales to
thermoelectrical and industrial segment. Sales to importers in
Italy (4.37 bcm) increased by 27.8% from 2018 due to the higher
availability of Libyan gas.
Sales in the European markets amounted to 22.70 bcm, a decrease
of 12.7% or 3.30 bcm from 2018. Sales in the Extra European
markets decreased by 0.11 bcm or 1.3% from the previous year,
due to lower LNG sales in the Far East markets, partly offset by
higher volumes sold in the United States.
Gas sales by market
ITALY
Wholesalers
Italian gas exchange and spot markets
Industries
Small and medium-sized enterprises and services
Power generation
Residential
Own consumption
INTERNATIONAL SALES
Rest of Europe
Importers in Italy
European markets:
Iberian Peninsula
Germany/Austria
Benelux
UK/Northern Europe
Turkey
France
Other
Extra European markets
WORLDWIDE GAS SALES
(bcm)
2019
70.39
37.85
25.56
6.98
2.68
1.51
1.17
73.07
2018
73.70
39.03
27.58
7.09
3.01
1.84
1.17
76.71
2017
77.52
37.43
36.10
3.99
3.31
2.13
1.18
80.83
Change
(3.31)
(1.18)
(2.02)
(0.11)
(0.33)
(0.33)
% Ch.
(4.5)
(3.0)
(7.3)
(1.6)
(11.0)
(17.9)
(3.64)
(4.7)
37.85 bcm
GAS SALES IN ITALY
6.25
3.99
1.90
0.87
4.92
(bcm)
Wholesalers
Italian gas exchange
and spot market
Industries
Small and medium-
size enterprises
Power generation
Residential
Own consumption
7.79
12.13
2019
37.85
7.79
12.13
4.92
0.87
1.90
3.99
6.25
35.22
27.07
4.37
22.70
4.22
2.10
3.77
1.75
5.56
4.48
0.82
8.15
73.07
2018
39.03
9.15
12.49
4.79
0.79
1.50
4.20
6.11
37.68
29.42
3.42
26.00
4.65
1.83
5.29
2.22
6.53
4.95
0.53
8.26
76.71
2017
37.43
8.36
10.81
4.42
0.93
2.22
4.51
6.18
43.40
38.23
3.89
34.34
5.06
6.95
5.06
2.21
8.03
6.38
0.65
5.17
80.83
Change
(1.18)
(1.36)
(0.36)
0.13
0.08
0.40
(0.21)
0.14
(2.46)
(2.35)
0.95
(3.30)
(0.43)
0.27
(1.52)
(0.47)
(0.97)
(0.47)
0.29
(0.11)
(3.64)
% Ch.
(3.0)
(14.9)
(2.9)
2.7
10.1
26.7
(5.0)
2.3
(6.5)
(8.0)
27.8
(12.7)
(9.2)
14.8
(28.7)
(21.2)
(14.9)
(9.5)
54.7
(1.3)
(4.7)
OPERATING REVIEW | GAS & POWER
53
LNG
Europe
Outside Europe
TOTAL LNG SALES
(bcm)
2019
5.5
4.6
10.1
2018
4.7
5.6
10.3
2017
5.2
3.1
8.3
Change
0.8
(1.0)
(0.2)
% Ch.
17.0
(17.9)
(1.9)
In 2019, LNG sales (10.1 bcm, included in the worldwide gas sales)
decreased by 1.9% from the 2018 and mainly concerned LNG from
Qatar, Nigeria, Indonesia and Oman and marketed in Europe, China,
Pakistan and Japan.
POWER
Availability of electricity
Eni’s power generation sites are located in Brindisi, Ferrera Erbognone,
Ravenna, Mantova, Ferrara and Bolgiano. As of December 31, 2019,
installed operational capacity of Enipower’s power plants was 4.7 GW
unchanged from 2018. In 2019, thermoelectric power generation was
21.66 TWh, substantially in line compared to 2018. Electricity trading
(17.83 TWh) reported an increase of 15.4% from 2018, thanks to the
optimization of inflows and outflows of power.
Power sales
In 2019, power sales of 39.49 TWh increased by 6.5% from the full year
2018 and were directed to the free market (72%), the Italian power
exchange (18%), industrial sites (9%) and other (1%). Compared to 2018,
power sales marketed in the free market increased by 2.40 TWh or by 9.3%,
due to higher volumes sold to wholesalers segment (up by 3.10 TWh),
middle market (up by 1.18 TWh) and residential (up by 1.18 TWh) partly
offset by lower volumes sold to the large customers (down by 3.23 TWh).
Purchases of natural gas
Purchases of other fuels
Power generation
Steam
AVAILABILITY OF ELECTRICITY
Power generation
Trading of electricity(a)
Availability
Free market
Italian Exchange for electricity
Industrial plants
Other(a)
Power sales
(mmcm)
(ktoe)
(TWh)
(ktonnes)
(TWh)
2019
4,410
276
21.66
7,646
2019
21.66
17.83
39.49
28.31
7.27
3.38
0.53
39.49
2018
4,300
356
21.62
7,919
2018
21.62
15.45
37.07
25.91
7.17
3.49
0.5
37.07
2017
4,359
392
22.42
7,551
Change
110
(80)
0.04
(273)
% Ch.
2.6
(22.5)
0.2
(3.4)
2017
22.42
12.91
35.33
26.53
5.21
3.01
0.58
35.33
Change
0.04
2.38
2.42
2.40
0.10
(0.11)
0.03
2.42
% Ch.
0.2
15.4
6.5
9.3
1.4
(3.2)
6.0
6.5
(a) Includes positive and negative imbalances (difference between the electricity effectively fed-in and as scheduled).
CAPITAL EXPENDITURE
In 2019, capital expenditure amounted to €230 million, mainly
relating to gas marketing initiatives (€176 million) and to the
maintenance, flexibility and upgrading initiatives of combined
cycle power plants (€42 million).
Marketing
Marketing
Italy
Outside Italy
Power generation
International transport
TOTAL CAPITAL EXPENDITURE
of which:
Italy
Outside Italy
(€ million)
2019
218
176
94
82
42
12
230
136
94
2018
207
161
93
68
46
8
215
139
76
2017
138
102
63
39
36
4
142
99
43
Change
11
15
1
14
(4)
4
15
(3)
18
OPERATING REVIEW | GAS & POWEREni Annual Report 2019
54
Refining & Marketing
and Chemicals
KEY PERFORMANCE INDICATORS
2019
2018
2017
(total recordable injuries/worked hours) x 1,000,000
TRIR (Total Recordable Injury Rate)
of which: employees
contractors
Sales from operations(a)
Operating profit (loss)
Adjusted operating profit (loss)
- Refining & Marketing
- Chemicals
Adjusted net profit (loss)
Capital expenditure
Refinery throughputs on own account in Italy and outside Italy
Conversion index(b)
Average refineries utilization rate(b)
Bio throughputs
Capacity of biorefineries(c)
Retail sales of petroleum products in Europe
Service stations in Europe at year end
Average throughput per service station in Europe
Retail efficiency index
Production of petrochemical products
Sale of petrochemical products
Average plant utilization rate
Employees at year end
of which: outside Italy
Direct GHG emissions
GHG emissions/Refinery throughputs (raw and semi-finished materials)
(€ million)
(mmtonnes)
(%)
(ktonnes)
(ktonnes/year)
(mmtonnes)
(number)
(kliters)
(%)
(ktonnes)
(%)
(number)
(mmtonnes CO2eq)
(tonnes CO₂ eq/ktonnes)
0.27
0.24
0.29
23,334
(854)
(48)
220
(268)
(75)
933
22.74
56
88
311
660
8.25
5,411
1,766
1.23
8,068
4,285
67
11,291
2,390
7.97
248
0.56
0.49
0.62
25,216
(380)
380
390
(10)
238
877
23.23
54
91
253
360
8.39
5,448
1,776
1.20
9,483
4,938
76
11,136
2,396
8.19
253
0.62
0.56
0.69
22,107
981
991
531
460
663
729
24.02
54
90
242
360
8.54
5,544
1,783
1.20
8,955
4,646
73
10,916
2,336
7.82
258
(a) Before elimination of intragroup sales.
(b) Since the participation interest in ADNOC Refining has been acquired effective August 1, 2019, the utilization rate has been calculated only for refineries owned or partecipated
for the full year. The conversion index include ADNOC Refining.
(c) Includes the pro-rata of installed capacity of Gela's biorefinery (720,000 tonnes/y) started in August 2019.
Performance of the year
˛ In 2019, the total recordable injury rate (TRIR) confirms
˛ GHG emissions relating to refining throughputs decreased by
Eni’s commitment in the field of health and security with a
decrease of 52% compared to 2018, with the contribution of
both employees and contractors.
˛ Greenhouse gas emissions (GHG) reported a decrease of 2.7%
in absolute terms as result of shutdowns of some chemical
plants.
2% thanks to energy efficiency measures.
˛ In 2019, the Refining & Marketing and Chemicals segment
reported an adjusted operating loss of €48 million,
representing a decrease of €428 million from the 2018
adjusted operating profit of €380 million.
The Refining & Marketing business reported an adjusted
ANDAMENTO OPERATIVO | REFINING & MARKETING E CHIMICA
55
operating profit of €220 million (down by 44%), due to the
unfavourable refining scenario, partially offset by a strong
marketing performance.
The Chemical business reported an adjusted operating loss
of €268 million, negatively affected by a depressed trading
environment due to a slowdown in demand from the main
end-markets, the weaker demand of single-use plastics and
the unavailability of the Priolo plant.
˛ Breakeven refining margin was 5.8 $/barrel in 2019, 3.5 $/
barrel assuming the budget scenario of exchange rates and
oil spreads, due to narrowing price differentials between
heavy crudes and the Brent market benchmark and to lower
product spreads, in particular lubricants and gasolines.
˛ In 2019 Eni’s refining throughputs amounted to 22.74
mmtonnes, slightly lower y-o-y (down by 2.1%) due to
lower throughputs at the Bayernoil refinery, following the
unavailability in the early nine months of the year of the
Vohburg facility, Livorno and Milazzo refineries, as well as the
PCK participated refinery. These negatives were partly offset
by higher volumes processed at the Taranto refinery.
˛ Production of biofuels from vegetable oil increased by 22.9%
from 2018 to 0.31 mmtonnes, driven by the start-up of the
Gela biorefinery in August 2019.
˛ Retail sales in Italy were 5.81 mmtonnes, slightly decreasing
by 1.7% from 2018.
˛ Retail sales in the Rest of Europe (2.44 mmtonnes) were
down by 1.6% compared to 2018, mainly due to lower volumes
traded in Germany, due to the event occurred at the Bayernoil
refinery and in France.
˛ Sales of petrochemical products amounted to 4.29
mmtonnes, recording a decrease of 13.2% y-o-y, mainly due
to lower intermediates sale volumes.
˛ Capital expenditure of €933 million mainly related to refining
activities.
Closing of the ADNOC Refining acquisition
In July 2019, finalized the acquisition of a 20% stake in ADNOC
Refining in Abu Dhabi, for a consideration of $3.24 billion, including
the 20% of a Trading Joint Venture to set-up for the oil products
marketing. This transaction is part of Eni’s strategy targeting portfolio
geographical diversification in order to balance Eni’s value chain, with
a 35% increase in its refining capacity.
Gela biorefinery start-up
In August 2019, Eni started-up the Gela biorefinery with an
installed capacity of 720,000 tonnes/year and equipped with
the EcofiningTM technology, developed by Eni, to convert into
biodiesel, vegetable oil and second generation raw materials,
such as used cooking oil and animal fat. The start-up of
Gela biorefinery represents a further step along the path to
decarbonisation of Eni’s activities.
Agreements to support circular economy in biofuels
In 2019, Eni signed some agreements for the joint development
of new solutions to support circular economy: with COREPLA
(National Consortium for the Collection, Recycling and Recovery
of Plastic Packaging) to produce hydrogen from non-recyclable
plastic packaging waste (plasmix); with Biogas Italian Consortium
to produce refined products for automotive from biogas and
biomethane; with Nextchem (Maire Tecnimont group) to
develop a conversion technology to transform civil waste and
non-recyclable plastic into fuels and chemical products; with
Coldiretti to produce biofuels from agricultural biomasses,
researching crops that do not compete with the food chain,
usable as alternative feedstock for biorefineries; with Italian
regions, in particular with Region of Lombardia, which joined the
Memorandum for sustainable development. These agreements
confirm Eni’s commitment towards innovative solutions to
promote the ongoing energy transition.
Integrated supply chain for the development of special polymers
In February 2020, Versalis acquired a 40% interest in Finproject,
the Italian leader company in the compounding business and in the
production of ultralight products, to create an integrated supply chain
of special polymers and to grow internationally. The acquisition,
through the development of innovative solutions in the fashion,
design and footwear sectors and for industrial applications, will allow
Versalis to leverage on more resilient businesses to the volatility
of the chemical scenario, thus exploiting its own expertise in the
polymer production and Finproject’s technology. This transaction is
subject to approval by the relevant authorities.
OPERATING REVIEW | REFINING & MARKETING AND CHEMICALS Eni Annual Report 2019 56
Development of circular economy in the chemical business
As a part of Eni’s commitment in the circular economy applied to
the chemical business, Eni developed Versalis Revive®, a line of
products (styrenics and polyethylene) made of post-consumer
plastic. The products have been developed in collaboration
with Montello SpA, leading operator in Europe in plastic
recovery and recycling technologies, with which Eni signed an
agreement to develop new processes for the transformation of
recycled packaging. Furthermore, Eni developed an expandable
polystyrene (Extir® FL3000) with enhanced mechanical
properties, able to minimizes the risk of plastic granules leaking
into the environment and to embed more recycled materials.
Digital transformation initiatives
In 2019, Eni launched certain digital transformation initiatives
mainly relating to: (i) the spread of new technologies and state of
the art devices to support the safety of workers of the Sannazzaro
and Venice refineries; (ii) the advanced monitoring of the pipeline
network with eVPMS-TPI (Third Parties Interference) system; and
(iii) the management and the evolution of the information systems
related to the Smart Mobility and to the e-payment, aimed at
improve customer care actions.
REFINING & MARKETING
SUPPLY AND TRADING
In 2019, were purchased 23.43 mmtonnes of crude (compared
with 22.62 mmtonnes in 2018), of which 4.24 mmtonnes by equity
crude oil, 14.06 mmtonnes on the spot market and 5.13 mmtonnes
by producing Countries with term contracts. The breakdown by
geographic area was as follows: 24% of purchased crude came from
the Middle East, 23% from Russia, 17% from Central Asia, 13% from
Italy, 13% from North Africa, 2% from West Africa, 2% from North Sea
and 6% from other areas.
Purchases
Equity crude oil
Other crude oil
Total crude oil purchases
Purchases of intermediate products
Purchases of products
TOTAL PURCHASES
Consumption for power generation
Other changes(a)
TOTAL AVAILABILITY
(mmtonnes)
2019
4.24
19.19
23.43
0.26
11.45
35.14
(0.35)
(2.08)
32.71
2018
4.14
18.48
22.62
0.65
11.55
34.82
(0.35)
(1.27)
33.20
2017
3.51
20.77
24.28
0.96
10.92
36.16
(0.34)
(1.76)
34.06
Change
0.10
0.71
0.81
(0.39)
(0.10)
0.32
(0.81)
(0.49)
% Ch.
2.4
3.8
3.6
(60.0)
(0.9)
0.9
(63.8)
(1.5)
(a) Include change in inventories, decrease due to transportation, consumption and losses.
REFINING
In 2019, Eni’s refining throughputs on own account in Europe were
22.74 mmtonnes, slightly decreased by 2.1% from 2018, due to:
the lower throughputs at the Bayernoil refinery, as a result of the
unavailability of the Vohburg facility in the early nine months of the
year following the event occurred in September 2018, the adverse
climatic events at the Milazzo refinery, as well as the participated
PCK refinery, affected by the Druzhba pipeline contamination.
These negatives were partially offset by higher volumes
processed by the Taranto refinery following lower maintenance
standstills.
In Italy, the refinery throughputs (20.70 mmtonnes) were in line
with 2018. The lower volumes processed at refineries affected by
higher maintenance standstills, logistic issues due to adverse
climatic events and the upset at the Milazzo refinery, as well as
the lower throughputs at the Livorno refinery to counteract the
scenario, were offset by higher volumes processed at the Taranto
refinery leveraging on fewer shutdowns.
Outside Italy, Eni’s refining throughputs on own account were
2.04 mmtonnes, down by approximately 510 ktonnes or 20% due
to the above mentioned downtime of the Bayernoil refinery. Total
throughputs in wholly-owned refineries were 17.26 mmtonnes, up
by 0.48 mmtonnes or 2.9% compared with 2018.
The refinery utilization rate, ratio between throughputs and refinery
capacity, is 88%.
Approximately 18.9% of processed crude was supplied by Eni’s
Exploration & Production segment, increasing by 18.3% from 2018.
OPERATING REVIEW | REFINING & MARKETING AND CHEMICALS
57
BIOREFINERY
The volumes of biofuels produced from vegetable oil increased by
22.9% compared to 2018, driven by the start-up of the Gela biorefinery
in August 2019, where full production ramp-up is underway, while the
Venice biorefinery has been hit by unplanned downtime.
Availability of refined products
ITALY
At wholly-owned refineries
Less input on account of third parties
At affiliated refineries
Refinery throughputs on own account
Consumption and losses
Products available for sale
Purchases of refined products and change in inventories
Products transferred to operations outside Italy
Consumption for power generation
Sales of products
Bio throughputs
OUTSIDE ITALY
Refinery throughputs on own account
Consumption and losses
Products available for sale
Purchases of refined products and change in inventories
Products transferred from Italian operations
Sales of products
REFINERY THROUGHPUTS ON OWN ACCOUNT
of which: refinery throughputs of equity crude on own account
TOTAL SALES OF REFINED PRODUCTS
Crude oil sales
TOTAL SALES
(mmtonnes)
2019
2018
2017
Change
% Ch.
17.26
(1.25)
4.69
20.70
(1.38)
19.32
7.27
(0.68)
(0.35)
25.56
0.31
2.04
(0.18)
1.86
4.17
0.68
6.71
22.74
4.24
32.27
0.44
32.71
16.78
(1.03)
4.93
20.68
(1.38)
19.30
7.50
(0.54)
(0.35)
25.91
0.25
2.55
(0.20)
2.35
4.12
0.54
7.01
23.23
4.14
32.92
0.28
33.20
16.03
(0.34)
5.46
21.15
(1.36)
19.79
6.74
(0.46)
(0.34)
25.73
0.24
2.87
(0.22)
2.65
4.36
0.46
7.47
24.02
3.51
33.20
0.86
34.06
0.48
(0.22)
(0.24)
0.02
0.02
(0.23)
(0.14)
(0.35)
0.06
(0.51)
0.02
(0.49)
0.05
0.14
(0.30)
(0.49)
0.10
(0.65)
0.16
(0.49)
2.9
(21.4)
(4.9)
0.1
0.1
(3.1)
(25.9)
(1.4)
22.9
(20.0)
10.0
(20.9)
1.2
25.9
(4.3)
(2.1)
2.4
(2.0)
57.1
(1.5)
MARKETING OF REFINED PRODUCTS
In 2019, retail sales of refined products (32.27 mmtonnes) were down
by 0.65 mmtonnes or by 2% from 2018, mainly due to the decrease of
sales to oil companies and petrochemical industry in Italy and lower
volumes marketed in the wholesalers segment in the Rest of Europe.
Product sales in Italy and outside Italy
(mmtonnes)
Retail
Wholesale
Petrochemicals
Other sales
Sales in Italy
Retail rest of Europe
Wholesale rest of Europe
Wholesale outside Europe
Other sales
Sales outside Italy
TOTAL SALES OF REFINED PRODUCTS
2019
5.81
7.68
0.83
11.24
25.56
2.44
2.63
0.48
1.16
6.71
32.27
2018
5.91
7.54
0.96
11.50
25.91
2.48
2.82
0.47
1.24
7.01
32.92
2017
6.01
7.64
0.86
11.22
25.73
2.53
3.03
0.45
1.46
7.47
33.20
Change
(0.10)
0.14
(0.13)
(0.26)
(0.35)
(0.04)
(0.19)
0.01
(0.08)
(0.30)
(0.65)
% Ch.
(1.7)
1.9
(13.5)
(2.3)
(1.4)
(1.6)
(6.7)
2.1
(6.5)
(4.3)
(2.0)
Retail sales in Italy
In 2019, retail sales in Italy were 5.81 mmtonnes, with a decrease
compared to 2018 (about 100 ktonnes from 2018 or down by
1.7%). Retail sales in the premium segment increased significantly.
Average gasoline and gasoil throughput (1,586 kliters) was
substantially in line with 2018. Eni’s retail market share of 2019
was 23.7%, slightly down from 2018 (24%). As of December 31,
2019, Eni’s retail network in Italy consisted of 4,184 service
stations, lower by 39 units from December 31, 2018 (4,223 service
stations), resulting from the negative balance of acquisitions/
releases of lease concessions (34 units), closure of low throughput
stations (6 units), partly offset by the net increase of 1 motorway
concession.
OPERATING REVIEW | REFINING & MARKETING AND CHEMICALS Eni Annual Report 2019
58
Retail and wholesale sales of refined products
(mmtonnes)
Italy
Retail sales
Gasoline
Gasoil
LPG
Others
Wholesale sales
Gasoil
Fuel Oil
LPG
Gasoline
Lubricants
Bunker
Jet fuel
Other
Outside Italy (retail+wholesale)
Gasoline
Gasoil
Jet fuel
Fuel Oil
Lubricants
LPG
Other
TOTAL RETAIL AND WHOLESALES SALES
2019
13.49
5.81
1.44
3.95
0.38
0.04
7.68
3.41
0.06
0.18
0.47
0.08
0.77
1.92
0.79
5.55
1.31
3.02
0.29
0.09
0.09
0.50
0.25
19.04
2018
13.45
5.91
1.46
4.03
0.38
0.04
7.54
3.25
0.07
0.20
0.44
0.08
0.80
1.98
0.72
5.77
1.30
3.16
0.33
0.14
0.09
0.50
0.25
19.22
2017
13.65
6.01
1.51
4.08
0.38
0.04
7.64
3.36
0.08
0.21
0.44
0.08
0.85
1.96
0.66
6.01
1.21
3.29
0.50
0.13
0.10
0.51
0.27
19.66
Change
0.04
(0.10)
(0.02)
(0.08)
0.14
0.16
(0.01)
(0.02)
0.03
(0.03)
(0.06)
0.07
(0.22)
0.01
(0.14)
(0.04)
(0.05)
% Ch.
0.3
(1.7)
(1.4)
(2.0)
1.9
4.9
(14.3)
(10.0)
6.8
(3.8)
(3.0)
9.7
(3.8)
0.8
(4.4)
(12.1)
(35.7)
(0.18)
(0.9)
RETAIL EFFICIENCY INDEX AND MARKET SHARE IN ITALY
Market share (%)
Retail efficiency index (%)
Service stations (No.)
24.3
1.20
24.0
1.20
23.7
1.23
0
1
3
,
4
7
1
0
2
3
2
2
,
4
8
1
0
2
4
8
1
,
4
9
1
0
2
Retail sales in the Rest of Europe
Retail sales in the Rest of Europe were 2.44 mmtonnes, recording
a slight reduction from 2018 (down by 1.6%) mainly due to lower
volumes traded in Germany, following the unavailability of the
Bayernoil plant and in France.
At December 31, 2019, Eni’s retail network in the Rest of Europe
consisted of 1,227 units, increasing by 2 units from December
31, 2018, mainly in Germany. Average throughput (2,356 kliters)
decreased by 35 kliters compared to 2018 (2,391 kliters).
Wholesale and other sales
Wholesale sales in Italy amounted to 7.68 mmtonnes,
increasing by 1.9% from 2018, mainly due to higher volumes
marketed of gasoil, bitumen and gasoline, partly offset by
lower sales of jet fuel and bunkers.
Wholesale sales in the Rest of Europe were 2.63 mmtonnes,
down by 6.7% from 2018 due to lower sold volumes in Germany
due to the unavailability of the Bayernoil refinery and France,
partly offset by higher volumes in Switzerland, Spain and
Austria.
Supplies of feedstock to the petrochemical industry (0.83
mmtonnes) decreased by 13.5%. Other sales in Italy and outside
Italy (12.40 mmtonnes) slightly decreased by 0.34 mmtonnes
or by 2.7%, mainly due to lower volumes sold to oil companies.
CHEMICALS
Product availability
Intermediates
Polymers
Production
Consumption and losses
Purchases and change in inventories
TOTAL AVAILABILITY
Intermediates
Polymers
TOTAL SALES
(ktonnes)
2019
5,818
2,250
8,068
(4,307)
524
4,285
2,519
1,766
4,285
2018
7,130
2,353
9,483
(5,085)
540
4,938
3,087
1,851
4,938
2017
6,595
2,360
8,955
(4,566)
257
4,646
2,748
1,898
4,646
Change
(1,312)
(103)
(1,415)
778
(16)
(653)
(568)
(85)
(653)
% Ch.
(18.4)
(4.4)
(14.9)
15.3
(3.0)
(13.2)
(18.4)
(4.6)
(13.2)
OPERATING REVIEW | REFINING & MARKETING AND CHEMICALS 59
Petrochemical sales of 4,285 ktonnes decreased from 2018
(down by 653 ktonnes, or 13.2%)mainly in ethylene, olefins
and derivatives.
Average sale prices of the intermediates business decreased by
9.9% from 2018, with derivatives and olefins down by 10.6% and
10.2%, respectively. The polymers reported a decrease of 10.8%
from 2018.
Petrochemical production of 8,068 ktonnes decreased
by 1.42 mmtonnes (down by 14.9%) mainly due to lower
production of intermediates business (down by 18.4%), in
particular aromatics and olefins; the polymers production of
2,250 ktonnes decreased by 4.4% from 2018 with elastomers,
polyethylene and styrenics down by 7%, 3.9% and 3.8%,
respectively.
The main decreases in production were registered at the
Priolo site (down by 23.3%), due to the event occurred at the
beginning of 2019 with the ramp-up finalized between April and
July, at the Porto Marghera (down by 21.9%) and Dunkerque
(down by 17.1%) sites due to unplanned shutdowns.
Plants nominal capacity is in line with the 2018. The average
plant utilization rate, calculated on nominal capacity,
was 66.8%, decreasing from 2018 (76.2%) following the
aforementioned shutdowns.
Polymers
Polymers revenues (€2,201 million) decreased by €388 million
or 15% from 2018 due to lower volumes sold (down by 4.6%), as
well as the decrease of the average prices (down by 10.8%). The
styrenics business registered the decrease of volumes sold (down
by 4.3%) for lower product availability; decrease of sale prices (down
by 14.7%). Polyethylene volumes decreased (down by 5%) due
to oversupply and mounting competitive pressure from cheaper
products streams from the Middle-East and the USA; decreasing
of average prices (down by 7.7%). In the elastomers business, a
decrease of sold volumes (down by 4.9%) was attributable to NBR
rubbers (down by 10.3%), thermoplastic rubbers (down by 14.8%)
and BR (down by 3.7%); increasing of SBR rubbers (up by 1.7%) and
lattices (up by 1%). Lower styrenics volumes sold (down by 2%)
were mainly driven by reduced sales of styrene (down by 13.8%),
and compact polystyrene (down by 5.9%); higher sales of ABS/SAN
(up by 12.9%) and expandable polystyrene (up by 0.4%). Overall,
the sold volumes of polyethylene business reported a decrease
(down by 5%) with lower sales of LLDPE and LDPE (down by 4.3% and
21.7%, respectively), while volumes of EVA increased (up by 39.9%).
Polymers productions (2,250 ktonnes) decreased from the 2018 due
to the lower production of elastomers (down by 7%), polyethylene
(down by 3.9%) and styrenics (down by 3.8%).
BUSINESS PERFORMANCES
CAPITAL EXPENDITURE
Intermediates
Intermediates revenues (€1,791 million) decreased by €610
million from 2018 (down by 25.4%) reflecting both the lower
commodity prices scenario influencing average intermediates
prices of main products and the lower product availability due
to plant standstills. Sales decreased by 18.4%, in particular
for ethylene business (down by 38%), olefins (down by
21.9%) and derivatives (down by 13.4%) following the lower
product availability. Average prices decreased by 9.9%, in
particular olefins (down by 10.2%), aromatics (down by 5.4%)
and derivatives (down by 10.6%). Intermediates production
(5,818 ktonnes) registered a decrease of 18.4% from the 2018.
Decreases were registered in aromatics (down by 19.6%), olefins
(down by 18.9%) and derivatives (down by 11.3%).
In 2019, capital expenditure in the Refining & Marketing and
Chemicals segment amounted to €933 million mainly regarding:
(i) refining activity in Italy and outside Italy (€683 million) aiming
fundamentally at reconstruction works of the EST conversion plant
at the Sannazzaro refinery, reconversion of Gela refinery into a
biorefinery, maintain plants’ integrity, reconversion of refinery
system, as well as initiatives in the field of health, security and
environment; (ii) marketing activity, mainly regulation compliance
and stay in business initiatives in the refined product retail
network in Italy and in the Rest of Europe (€132 million); (iii) in
the Chemical business, maintenance (€67 million), environmental
protection, safety and environmental regulation (€26 million),
upgrading and decarbonization activities (€20 million).
Research and Development (R&D) expenditure in the Refining &
Marketing and Chemicals segment amounted to approximately €48
million. During the year, 8 patent applications were filed.
Refining
Marketing
Chemicals
TOTAL CAPITAL EXPENDITURE
(€ million)
2019
683
132
815
118
933
2018
587
139
726
151
877
2017
395
131
526
203
729
Change
96
(7)
89
(33)
56
OPERATING REVIEW | REFINING & MARKETING AND CHEMICALS Eni Annual Report 2019
60
Corporate
and other activities
KEY PERFORMANCE INDICATORS
2019
2018
2017
(total recordable injuries/worked hours) x 1,000,000)
TRIR (Total Recordable Injury Rate)
of which: employees
contractors
Sales from operations(a)
Operating profit (loss)
Adjusted operating profit (loss)
Adjusted net profit (loss)
Capital expenditure
Photovoltaic/wind installed capacity
Electricity produced from renewable sources
Groundwater treatment
Groundwater treated at TAF plants and used in the production cycle or reinjected
Waste disposed
Recovered waste vs. recoverable waste
R&D expenditure
First patent filing application
Employees at year end
of which: outside Italy
(€ million)
(MW)
(GWh)
(mmcm)
(mmtonnes)
(%)
(€ million)
(number)
(number)
0.51
0.20
1.01
1,681
(710)
(624)
(884)
231
167
66.9
30.7
5.1
2.0
59
75
14
6,245
254
0.53
0.55
0.48
1,589
(691)
(606)
(965)
143
40
19.3
29.7
4.8
1.9
58
57
13
5,880
238
0.41
0.21
1.00
1,462
(668)
(542)
(1,041)
87
n.d.
16.1
22.2
4.2
1.3
48
44
7
5,735
234
(a) Before elimination of intragroup sales.
The “Corporate and other activities” includes the following businesses:
(i) the “Corporate and financial companies” segment includes results of operations of Eni’s headquarters (Group strategic planning,
human resources management, finance, administration, information technology, legal affairs, international affairs and corporate research
and development functions) and Eni’s subsidiaries (Eni Finance International SA, Banque Eni SA, Eni International BV, Eni Finance USA Inc,
Eni Insurance DAC, EniServizi, Eni Corporate University, AGI and other minor subsidiaries) which carries out cash management activities,
finance, general purposes services and support to Group businesses; (ii) the “other activities” segment comprises results of operations
of Eni’s subsidiary Eni Rewind, which runs reclamation and decommissioning activities pertaining to certain businesses which Eni exited,
divested or shut down in past years and manages the stream of waste originated from industrial and remediation activities, as well as
Energy Solutions business which engages in developing the business of renewable energy.
61
Performance of the year
˛ In 2019, the total recordable injury rate (TRIR) of the workforce
reported a better performance compared to 2018, thanks to the Eni’s
constant commitment to ensure safety in the workplaces. In the
year, initiatives continued, for both Eni’s employees and contractors,
for the dissemination of the safety culture and in particular to
promote safe and correct behaviours in all environments. The “Safety
starts @ office” campaign was launched to support safety in offices
and headquarters starting from the “Safety Golden Rules”.
˛ In 2019, the groundwater treated at TAF plants and used in the
production cycle or reinjected increased by over 6%. This result
confirms Eni’s commitment in the growth of groundwater share
reclaimed and reused for civil or industrial purposes, in the start-
up of initiatives and assessments for the use of low-quality water
in place of freshwater and the decrease of water intensity in the
operations.
˛ Renewable energy installed capacity achieved 167 MW.
˛ In 2019, the Corporate and Other activities segment reported an
increase of revenues of approximately 6% mainly as a result of the
growth of global client activities, the environmental logistic services,
as well as remediation initiatives carried out for Eni’s Group.
˛ Capital expenditure (€231 million) were mainly focused on
the development of renewable projects, circular economy and
digitalization.
˛ In 2019, research and development expenditure amounted to
€75 million (€57 million in 2018). 14 patent applications were
filed.
˛ In 2019, were managed waste for a total amount of 2
mmtonnes, the share of recovered/recycled waste increased
by 5% compared to 2018.
Activities of the year
RENEWABLE ENERGIES
Eni’s commitment to the development of renewables projects
is going on, reaching a total installed capacity of 167 MW as of
December 31, 2019, of which 82 MW in Italy and approximately
86 MW outside Italy.
Italy
˛ Among the "Progetto Italia", the photovoltaic plant at the
industrial hub of Porto Torres in Sardinia was started-up,
with an installed capacity of 31 MW. Energy produced will be
addressed for a total share of 70% to own consumptions of the
companies located in the industrial site.
˛ As of December 31, 2019, finalized around the 90% of the
photovoltaic plant in Volpiano (Piemonte) with a total capacity
of 18 MW (completed in January 2020).
Kazakhstan
˛ In 2019, realized the 70% of Badamsha plant, the first Eni’s
wind farm energy with a total capacity of 50 MW (completed
in February 2020). The project, in partnership with General
Electric (GE), is part of the agreement signed in 2017, by Eni,
GE and the Minister of the Republic of Kazakhstan.
Australia
˛ Completed the Katherine plant in the Northern Region with
a total capacity of 34 MW, integrated with an energy storage
system and an installed storage power of about 6 MW.
in an offgrid configuration. The peak capacity amounts to 10
MW, with a production of approximately 20 GWh/year. This plant
allows to reduce gas consumptions.
Tunisia
˛ Completed the 5 MW photovoltaic system (Eni's interest 50%)
in the Adam concession. The plant provides a storage battery
system (with an installed storage capacity of 2.2 MW) which
allows to support integration with the already existing gas
turbines.
˛ The construction of a photovoltaic system with an installed
capacity of 10 MW (Eni's interest 50%) is ongoing in the city
of Tataouine. This project, awarded following a public tender
launched by the Tunisian Ministry of Energy, provides the
supply of green electricity to theState-owned company STEG
(Société Tunisienne de l'Electricité et du Gaz).
CIRCULAR ECONOMY
˛ Development of the Waste to Fuel technology for the
transformation of organic waste into refining intermediates,
fuels components for fuels or chemical basis. In 2019, Eni
Rewind started the identification of possible development
opportunities in Italy. In particular, feasibility studies of a
Waste to Fuel plant were realized at Porto Marghera, with a
FORSU processing capacity until 150,000 tonnes per year.
Pakistan
˛ In November 2019, started the Bhit photovoltaic plant, the
first Eni’s solar project in Pakistan. This plant, supporting the
production facilities at the Bhit gas field, provides solar energy
˛ In 2019, Eni Rewind started the engineering phase of the first
application on an industrial scale of its proprietary technology
“Blue Water”, for the treatment and recovery of produced water
extracted from the reservoir. Inquiry is underway to obtain
authorizations by local authorities.
OPERATING REVIEW | CORPORATE AND OTHER ACTIVITIESEni Annual Report 2019 62
New initiatives in portfolio
˛ In September and November 2019, following two competitive
tenders, ArmWind LLP (Eni 100%) obtained the rights for the
construction of a 48 MW wind farm energy in the Badamsha area
and a 50 MW photovoltaic plant in the Southern Kazakhstan in the
Shauldir area.
˛ In October 2019, completed the acquisition of a project for the
construction of two 12.5 MW photovoltaic power plants each,
at the Batchelor and Manton Dam sites in the Northern Area of
Australia. The plants will be in production by the third quarter
of 2020.
Strategic partnerships
In March 2019, Eni and Cassa Depositi e prestiti (CDP) signed a
Memorandum of Understanding (MoU) aimed at the identification
of projects in Italy in the field of circular economy, decarbonization
and sustainability. In particular, the building of plants for the
production of electricity from renewable sources, also leveraging on
the relaunch of industrial sites and the joint realization of plants for
the transformation of organic waste into bio oil and water. In August
2019, Eni Rewind and CDP signed an agreeement for the realization
of four Waste to Fuel plants with a total capacity of over 600
ktonnes per year. The engineering activities of the first industrial
plant is ongoing at the reclaimed area of Porto Marghera.
In September 2019, Eni and Mainstream Renewable Power, a wind
and solar energy company, signed a cooperation agreement to
develop large-scale projects from renewable sources, mainly in
Africa, in the South-East Asia, and with an initial focus in the UK.
In October 2019, Eni, CDP, Fincantieri and Terna signed an agreement
for the construction of power generation plants from waves, realizing
on an industrial scale, initially on the Italian territory, the pilot project
Inertial Sea Wave Energy Converter (ISWEC).
In December 2019, Eni signed an agreement with Falck Renewables
for the joint development of renewable energy projects in the United
States, targeting at least 1 GW of installed capacity by the end of
2023. Eni will also acquire a 49% stake in Falck already existing plants
in the USA (116 MW capacity, included a storage system of 3 MW).
A Concession Agreement was signed in Angola for the construction
(in two phases) of a 50 MW photovoltaic system in the province of
Namibe. The plant will be built by Solenova, a joint venture between
Eni and Sonangol and will be connected to the transmission
network in the Southern part of the Country.
A Memorandum of Understanding was signed with the Polytechnic
of Turin for a collaboration in studying all marine energy sources,
from wave motion to offshore wind, ocean and tidal currents and
salt gradient.
OPERATING REVIEW | CORPORATE AND OTHER ACTIVITIES Financial review
IFRS 16 adoption
63
Eni’s 2019 consolidated financial statements and the reclassified
statements of profit and loss, cash flow and financial position
commented in this section have been prepared incorporating
in full the effects of the new IFRS 16 “Leases”, effective at the
beginning of the year, which defines a lease as a contract that
conveys to the lessee the right to control the use of an identified
asset for a period of time in exchange for consideration and
eliminates the classification of leases as either operating leases
or finance leases for the preparation of the lessee’s financial
statements. The new accounting standard has determined a
significant impact on the Group key performance indicators in its
consolidated financial statements, particularly in net borrowings,
with a steep up effect due to the fact that Eni has adopted the
modified retrospective approach, by recognizing the cumulative
effect of initially applying the new standard as an adjustment
to the opening balance at January 1, 2019, without restating
the comparative periods. Additional information about adoption
of IFRS 16 with regard to assumptions and practical expedients
used in the first application are provided in the notes to the
consolidated financial statements under the heading “change
to accounting criteria”. A brief description of the new accounting
of lease contracts under IFRS 16 and the main effects on the
reclassified financial statements are provided below.
The accounting of the new standard applies to all leases that have
a lease term of more than 12 months and requires:
-
in the balance sheet, the recognition in dedicated entries of
assets and liabilities of a right-of-use asset, that represents
a lessee’s right to use an underlying asset (ROU), and a
lease liability (LL) of the same amount, that represents the
lessee’s obligation to make the contractual lease payments
recorded at their present value. Therefore compared to the
previous accounting of operating leases, the new accounting
standard has driven the recognition of a significant
liability that has been classified as part of the Company’s
net borrowings with a proportional increase in the Group
leverage;
in the profit and loss account, the depreciation charges of the
ROU asset and, the interest expense on the LL are recognized
within operating expenses and finance expense, respectively.
Under the previous accounting, the operating lease payments
were recorded within operating costs. The depreciation charges
-
-
of the ROU asset and the interest expense on the LL attributable
recorded as part of the construction of an asset are capitalized
as part of the cost of such asset and subsequently recognized
in the profit and loss account through depreciation;
in the statement of cash flows, the reimbursement of
the principal portion of the LL is recorded as part of net
cash used in financing activities. Interest expenses are
recorded as part of net cash provided by operating activities,
or of net cash used in investing activities depending
whether are recognized in the profit and loss account or
capitalized in the case of leased assets that are used for
the construction of other assets. Consequently, compared
with the requirements of IAS 17 related to operating leases,
the adoption of IFRS 16 determined a significant impact in
the statement of cash flows due to: (a) an improvement in
net cash provided by operating activities, which no longer
includes the operating lease payments, but only includes
the cash payments for the interest portion of the LL that
are not capitalized; (b) an improvement in net cash used
in investing activities, which no longer includes capitalized
lease payments, but only includes cash payments for the
capitalized interest portion of the lease liability; and (c) an
increase in the net cash used in financing activities, which
includes cash payments for the principal portion of the LL.
Finally, it is worth noting that the initial amount of Eni’s LL is
affected by the fact that in the E&P sectors Oil & Gas projects are
carried out based on the contractual scheme of unincorporated
joint operations managed by one of the joint operators (the
lead operator). This structure entails that the LL relating lease
contracts entered into by the lead operator on behalf of the joint
operations is recorded in full in the financial statements of the
lead operator, because the operator is normally the sole signatory
of the lease contract and consequently takes the primary
responsibility for discharging the lease obligations towards the
third-party lessor, independently from the fact that the operator
is able to recover the lease payments through a partner billing
process. Consistently, the ROU of the asset utilized by the joint
operations is recorded 100% by the operator. On the contrary, in
case all co-venturers sign jointly a lease contract each of them
recognizes its proportionate share of the ROU asset of the LL.
(€ million)
Purchases, services and other
Depreciation, depletion and amortization
Operating profit
Finance expense and income taxes
Net profit
Full Year 2019
Profit and loss account
IFRS 16 effects
1,034
(830)
204
(332)
(128)
before IFRS 16
(51,908)
(7,276)
6,228
(9,338)
283
GAAP results
(50,874)
(8,106)
6,432
(9,670)
155
64
Fixed assets
Net working capital
Net borrowings
Shareholders' equity
Leverage
(€ million) before IFRS 16 opening balance
71,567
(11,324)
8,289
51,073
0.16
January 1, 2019
Balance Sheet
IFRS 16 effects
5,643
116
5,759
Cash Flow From Operations (FFO)
Capital expenditure
Free Cash Flow (FCF)
Cash Flow From Financing, net (CFFF)
Net increase (decrease) in cash and cash equivalent
(€ million)
Full Year 2019
Cash Flow
IFRS 16 effects
666
211
877
(877)
before IFRS 16
11,726
(8,587)
381
(4,964)
(4,861)
GAAP results
77,210
(11,208)
14,048
51,073
0.28
GAAP results
12,392
(8,376)
1,258
(5,841)
(4,861)
PROFIT AND LOSS ACCOUNT
Sales from operations
Other income and revenues
Operating expenses
Other operating income (expense)
Depreciation, depletion, amortization
Impairment reversals (impairment losses) of tangible
and intangible and right of use assets, net
Write-off of tangible and intangible assets
Operating profit (loss)
Finance income (expense)
Income (expense) from investments
Profit (loss) before income taxes
Income taxes
Tax rate (%)
Net profit (loss)
attributable to:
- Eni's shareholders
- Non-controlling interest
(€ million)
2019
69,881
1,160
(54,302)
287
(8,106)
2018
75,822
1,116
(59,130)
129
(6,988)
2017
66,919
4,058
(55,412)
(32)
(7,483)
Change
(5,941)
44
4,828
158
(1,118)
(2,188)
(866)
225
(1,322)
(300)
6,432
(879)
193
5,746
(5,591)
97.3
155
(100)
9,983
(971)
1,095
10,107
(5,970)
59.1
4,137
(263)
8,012
(1,236)
68
6,844
(3,467)
50.7
3,377
(200)
(3,551)
92
(902)
(4,361)
379
38.2
(3,982)
% Ch.
(7.8)
3.9
8.2
..
(16.0)
..
..
(35.6)
9.5
..
(43.1)
6.3
(96.3)
148
7
4,126
11
3,374
3
(3,978)
(4)
(96.4)
..
Reported results
In the full year 2019, the Group reported net profit attributable
to Eni’s shareholders of €148 million (€4,126 million in the full
year 2018). The reported operating profit was €6,432 million,
approximately 36% lower than in 2018, down by €3.6 billion;
approximately 80% of the decline is related to the E&P segment.
The 2019 results were negatively affected by a challenging
operating and trading environment, reflecting a slowdown in the
global macroeconomic cycle, a deceleration in international trade
triggered by the "trade dispute" between the US and China, as well
as by adverse geopolitical developments that fueled uncertainty
among market participants and directly affected Eni's performance
in certain areas. All of these factors have curbed demand for
energy commodities and global consumption of fuels and plastics,
increasing the negative impact of oil and gas overproduction on
upstream business, while rising competition from producers with
more efficient cost structures and overcapacity pressured margins
in our downstream businesses of refining and chemical. Against
this backdrop, the Group reported a decline in oil and gas realized
prices as well as in products margins in all of its business segments.
Prices and margins reductions negatively affected operating profit
for an estimated €2.5 billion. The main negative factors were lower
gas prices in all geographies with the worst declines recorded by
the European benchmark gas spot price “Italy PSV”, which was
down by 34% as well as by LNG margins. The performance was
also negatively affected by a number of incidents at production
plants, such as the fire that occurred at the Priolo chemical cracker
in January, and unplanned standstills or outages, like in the case
of the Goliat oilfield in Norway, the Bayernoil refinery, the Porto
Marghera and the Dunkerque crackers. These negative effects
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEW
65
were partly offset by higher hydrocarbon production which
achieved a new record plateau at 1.87 million boe/d, efficiency and
optimization measures and steady results reported by the retail
businesses (Gas & Power retail segment as well as the marketing
of fuels at both retail and wholesale markets), notwithstanding
the fact that these activities are not shielded by entry barriers,
leveraging on effective marketing actions and continuing product/
service innovation. Furthermore, the operating profit was
negatively affected by the incurrence of approximately €2.2 billion
of impairment losses, which were mainly recorded at Oil & Gas
properties and refineries mainly driven by a revised refining margin
scenario and lower performance of the fields.
Net profit for the year was also negatively affected by lower net
income from investments (down by €902 million), due to the fact
that the 2018 financial statements accounted for the gains on the
Vår Energi business combination (€889 million) and a reversal of a
prior-year impairment loss of €262 million made at the Angola LNG
equity-accounted entity. Finally, net profit was negatively affected
by an increased tax rate, which was due to a higher share of taxable
incomes reported by the Exploration & Production segment in
Countries subject to higher-than-average tax rates, lower reselling
margin on volumes of Libyan gas due to a partner, while taxable
losses were incurred in jurisdictions with a lower-than-average
statutory tax rate. The Group tax rate was also impacted by the write-
off of Italian deferred tax assets of approximately €0.9 billion due to
projections of lower future taxable profit at Italian subsidiaries.
The adoption of IFRS 16 determined a €204 million improvement
in the reported operating profit due to fees for the rental of assets
no longer being recognized as an expense, partly offset by the
recognition of the amortization of the right-of-use assets, equal to
the present value of the expected future lease payments. Instead,
the IFRS 16 impact on net profit was a negative €128 million
because the improved operating profit was more than offset by
interest charges accrued on the lease liabilities. This was due to the
fact that amortization charges of the ROU asset are calculated based
on the straight-line method, whereas interest expense on the lease
liability accrues proportionally to the amount of the financial liability.
The table below shows the main scenario indicators:
Average price of Brent dated crude oil in US dollars(a)
Average EUR/USD exchange rate(b)
Average price of Brent dated crude oil in euro
Standard Eni Refining Margin (SERM)(c)
PSV(d)
TTF(d)
2019
64.30
1.119
57.44
4.3
171
142
2018
71.04
1.181
60.15
3.7
260
243
2017
54.27
1.130
48.03
5.0
211
183
% Ch.
(9.5)
(5.2)
(4.5)
16.2
(34.2)
(41.6)
(a) Price per barrel. Source: Platt’s Oilgram.
(b) Source: ECB.
(c) In $/BBL FOB Mediterranean Brent dated crude oil. Source: Eni calculations. Approximates the margin of Eni's refining system in consideration of material balances and refine-
ries' product yields.
(d) €/kcm.
Adjusted results
Operating profit (loss)
Exclusion of inventory holding (gains) losses
Exclusion of special items
Adjusted operating profit (loss)
Net profit (loss) attributable to Eni's shareholders
Exclusion of inventory holding (gains) losses
Exclusion of special items
Adjusted net profit (loss) attributable to Eni's shareholders
Tax rate (%)
(€ million)
2019
6,432
(223)
2,388
8,597
148
(157)
2,885
2,876
64.2
2018
9,983
96
1,161
11,240
4,126
69
388
4,583
56.2
2017
8,012
(219)
(1,990)
5,803
3,374
(156)
(839)
2,379
56.8
Change
(3,551)
% Ch.
(35.6)
(2,643)
(23.5)
(3,978)
(96.4)
(1,707)
(37.2)
In the full year of 2019, adjusted operating profit of €8,597 million
decreased by 24% from the full year of 2018. Excluding the impact
of the loss of control over Eni Norge on the 2018 results to allow
a-like-for-like comparison, and net of scenario effects, of the lower
time value of money and IFRS 16 accounting, the adjusted operating
profit increased by 5%. This trend reflects the E&P segment
contribution which reported an improved performance (up by 7%)
excluding the result of Eni Norge from 2018, and net of scenario
effects, IFRS 16 accounting and the impact of lower interest rates
on the present value of the ARC (asset retirement cost) resulting in
higher DD&A, due to higher productions.
The G&P segment reported an adjusted operating profit of €654
million, up by 20%. The wholesale business performance was
boosted mainly by optimizations at the gas and power assets
portfolio in Europe which enabled the business to capture the
upsides associated with a highly-volatile environment, partly offset
by the weaker LNG business result due to a worsening environment
in Asia which affected margins and volumes. The retail business
benefited from more effective commercial initiatives, higher extra-
commodity revenues, and lower expenses.
The R&M and Chemicals segment was negatively affected by a
deteriorated refining scenario, as well as by rising competitive
pressure in the chemical business.
Adjusted net profit of €2.876 million decreased by 37% due to the
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEWEni Annual Report 2019
66
weaker operating performance, partly offset by the improvement
(up by €135 million) of the finance income (expense), reflecting
the circumstances that the 2018 included finance charges due to
the write-off of financing receivables related to an unsuccessful
exploration initiative executed by a joint venture in the Black Sea.
The adjusted tax rate was 64%, increasing by approximately 8
percentage points from 2018, due to a higher share of taxable
income reported by the Exploration & Production segment in
Countries subject to higher-than-average tax rates and lower
reselling margins on volumes of gas entitlements of a Libyan
partner, while taxable losses were incurred in jurisdictions with a
lower-than-average statutory tax rate.
Net profit includes special items resulting in net charges of
€2,885 million:
(i) net impairment losses of oil and gas properties in the E&P
(ii)
segment due to downward reserves revisions and lower
expected production rates, as well as of certain assets to align
the book value to fair value (€1,217 million);
impairment losses mainly recorded at the Sannazzaro
refinery reflecting a revised margin outlook both at high and
low-complexity cycles, higher projected expenses as well
as the write-down of capital expenditure relating to certain
Cash Generating Units in the R&M business. These units were
impaired in previous reporting periods and continued to lack any
profitability prospects (for an overall impact of €819 million);
(iii) the impairment of Chemical assets due to a lowered
profitability outlook (€103 million);
(iv) the impairment of power plants (€42 million) due to the
deterioration of the Clean Spark Spread scenario;
(v) net gains on the divestment of certain Oil & Gas properties,
mainly the sale of an interest in the Merakes discoveries to
Neptune (€145 million);
(vi) environmental provisions (€338 million) mainly in R&M and
Chemicals segment;
(vii) an insurance compensation (€88 million) relating to the EST
plant at the Sannazzaro refinery;
(viii) the accounting effect of certain fair-valued commodity
derivatives lacking the formal criteria to be classified as
hedges or to be eligible for the own use exemption (a gain of
€423 million);
(ix) the difference between the change in gas inventories
accounted under the weighted-average cost method provided
by IFRS and management’s own measure of inventories.
This moves the margins captured on volumes in inventories
forward at the time of inventory drawdown above their normal
levels leveraging the seasonal spread in gas prices net of the
effects of the associated commodity derivatives (a charge of
€145 million);
the reclassification to adjusted operating profit of the positive
balance of €108 million related to derivative financial
instruments used to manage margin exposure to foreign
currency exchange rate movements, and exchange translation
differences of commercial payables and receivables;
(xi) tax effects relating to operating special items, as well as the
write-down of deferred taxes relating to Italian subsidiaries
due to a deteriorated profitability outlook (€893 million).
(x)
Breakdown of special items
Special items of operating profit (loss)
- environmental charges
- impairment losses (impairments reversal), net
- net gains on disposal of assets
- risk provisions
- provision for redundancy incentives
- commodity derivatives
- exchange rate differences and derivatives
- reinstatement of Eni Norge amortization charges
- other
Net finance (income) expense
of which:
- exchange rate differences and derivatives reclassified to operating profit (loss)
Net (income) expense from investments
of which:
- gains on disposal of assets
- impairments/revaluation of equity investments
Income taxes
of which:
- net impairment of deferred tax assets of Italian subsidiaries
- USA tax reform
- taxes on special items of operating profit and other special items
Total special items of net profit (loss)
(€ million)
2019
2,388
338
2,188
(151)
3
45
(439)
108
296
(42)
2018
1,161
325
866
2017
(1,990)
208
(221)
(452)
(3,283)
380
155
(133)
107
(375)
288
(85)
448
49
146
(248)
911
502
248
372
(108)
188
(107)
(798)
(46)
(909)
(163)
148
351
893
(542)
2,885
67
110
99
11
388
537
277
115
162
(839)
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEW
67
The breakdown by segment of the adjusted net profit is provided in the table below:
Exploration & Production
Gas & Power
Refining & Marketing and Chemicals
Corporate and other activities
Impact of unrealized intragroup profit elimination and other consolidation adjustments(a)
Adjusted net profit (loss)
attributable to:
- Eni's shareholders
- Non-controlling interest
(€ million)
2019
3,436
426
(75)
(884)
(20)
2,883
2,876
7
2018
4,955
310
238
(965)
56
4,594
4,583
11
2017
2,724
52
663
(1,041)
(16)
2,382
Change
(1,519)
116
(313)
81
(76)
(1,711)
2,379
3
(1,707)
(4)
% Ch.
(30.7)
..
..
8.4
(37.2)
(37.2)
..
(a) This item concerned mainly intragroup sales of commodities, services and capital goods recorded in the assets of the purchasing business segment as of end of the period.
Profit and loss analysis
Total revenues
Exploration & Production
Gas & Power
Refining & Marketing and Chemicals
- Refining & Marketing
- Chemicals
- Consolidation adjustments
Corporate and other activities
Consolidation adjustments
Sales from operations
Other income and revenues
Total revenues
(€ million)
2019
23,572
50,015
23,334
19,640
4,123
(429)
1,681
(28,721)
69,881
1,160
71,041
2018
25,744
55,690
25,216
20,646
5,123
(553)
1,589
(32,417)
75,822
1,116
76,938
2017
19,525
50,623
22,107
17,688
4,851
(432)
1,462
(26,798)
66,919
4,058
70,977
Change
(2,172)
(5,675)
(1,882)
(1,006)
(1,000)
92
3,696
(5,941)
44
(5,897)
% Ch.
(8.4)
(10.2)
(7.5)
(4.9)
(19.5)
5.8
(7.8)
3.9
(7.7)
Total revenues amounted to €71,041 million, reporting a decrease
of 7.7%.
Sales from operations in the full year of 2019 (€69,881 million)
decreased by €5,941 million or down by 7.8% from 2018, with the
following breakdown:
- revenues generated by the Exploration & Production segment
(€23,572 million) decreased by 8.4% due to lower average
realizations on equity hydrocarbons in dollar terms of 8.3% driven
by lowering prices for the marker Brent and gas prices in Europe.
Finally, y-o-y comparability was negatively affected by the de-
recognition of our former subsidiary Eni Norge at the end of 2018;
- revenues generated by the Gas & Power segment (€50,015
million) decreased by €5,675 million or down by 10.2%. The
decrease reflected lower natural gas prices in Europe and
declining LNG prices due to a weaker Asian scenario and lower
volumes sold;
- revenues generated by the Refining & Marketing and Chemicals
segment (€23,334 million) decreased by €1,882 million (down
by 7.5%) due to lower average selling prices of gasoline and gasoil
in the Refining & Marketing business, as well as the decline
in average selling prices and reducing volumes sold, mainly
intermediates, in the Chemical business.
Operating expenses
Purchases, services and other
Impairment losses (impairment reversals) of trade and other receivables, net
Payroll and related costs
of which: provision for redundancy incentives and other
(€ million)
2019
50,874
432
2,996
45
54,302
2018
55,622
415
3,093
155
59,130
2017
51,548
913
2,951
49
55,412
Change
(4,748)
17
(97)
% Ch.
(8.5)
4.1
(3.1)
(4,828)
(8.2)
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEWEni Annual Report 2019
68
In 2019 operating expenses for 2019 (€54,302 million) decreased
by €4,828 million from 2018, down by 8%. Purchases, services
and other (€50,874 million) decreased by approximately 9%
mainly reflecting lower costs for hydrocarbon supplies (natural
gas under long-term supply contracts and refinery and chemical
feedstocks). Payroll and related costs (€2,996 million) decreased
by €97 million from 2018, mainly due to the circumstance that in
2018 higher provisions for redundancy incentives were accounted
relating to an early retirement program in the Eni gas e luce SpA
subsidiary in accordance with Art. 4 of Italian Law No. 92/2012.
Depreciation, depletion, amortization, impairment losses (impairment reversals) net and write-off
Exploration & Production
Gas & Power
Refining & Marketing and Chemicals
Corporate and other activities
Impact of unrealized intragroup profit elimination
Total depreciation, depletion and amortization
Impairment losses (impairment reversals) of tangible
and intangible and right of use assets, net
Depreciation, depletion, amortization, impairments and reversals, net
Write-off of tangible and intangible assets
(€ million)
2019
7,060
447
485
146
(32)
8,106
2,188
2018
6,152
408
399
59
(30)
6,988
2017
6,747
345
360
60
(29)
7,483
Change
908
39
86
87
(2)
1,118
866
(225)
1,322
10,294
300
10,594
7,854
100
7,954
7,258
263
7,521
2,440
200
2,640
% Ch.
14.8
9.6
21.6
..
16.0
..
31.1
..
33.2
Depreciation, depletion and amortization (€8,106 million)
increased by 16% from 2018, in particular in the Exploration &
Production segment mainly due to the depreciation charges of
the right-of-use asset in accordance to IFRS 16, which provided
a new accounting framework for operating leases without
restating the comparative periods, higher charges recorded
in connection with an upward revision of the present value of
capitalized assets retirement costs due to lower interest rates,
as well as fields started-up and new projects ramp-up.
Net impairment losses (impairment reversals) of tangible and
intangible and right of use assets amounted to €2,188 million
and the disclosure is provided under the paragraph “special
items”. The breakdown by segment is provided below:
Exploration & Production
Gas & Power
Refining & Marketing and Chemicals
Corporate and other activities
Impairment losses (impairment reversals) of tangible
and intangible and right of use assets, net
(€ million)
2019
1,217
37
922
12
2,188
2018
726
(71)
193
18
866
2017
(158)
(146)
54
25
Change
491
108
729
(6)
(225)
1,322
Write-off charges amounted to €300 million and mainly related
to previously capitalized costs of exploratory wells which were
expensed through profit because it was determined that they did
not encounter commercial quantities of hydrocarbons mainly in
Australia, Kazakhstan and Pakistan.
Operating profit
The breakdown by segment of the operating profit is provided below:
Exploration & Production
Gas & Power
Refining & Marketing and Chemicals
Corporate and other activities
Impact of unrealized intragroup profit elimination
Operating profit (loss)
(€ million)
2019
7,417
699
(854)
(710)
(120)
6,432
2018
10,214
629
(380)
(691)
211
9,983
2017
7,651
75
981
(668)
(27)
8,012
Change
(2,797)
70
(474)
(19)
(331)
(3,551)
% Ch.
(27.4)
11.1
..
(2.7)
(35.6)
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEW
69
Adjusted operating profit
The breakdown by segment of the adjusted operating profit is provided below:
Operating profit (loss)
Exclusion of inventory holding (gains) losses
Exclusion of special items
Adjusted operating profit (loss)
Breakdown by segment:
Exploration & Production
Gas & Power
Refining & Marketing and Chemicals
Corporate and other activities
Impact of unrealized intragroup profit elimination
and other consolidation adjustments
(€ million)
2019
6,432
(223)
2,388
8,597
8,640
654
(48)
(624)
(25)
2018
9,983
96
1,161
11,240
10,850
543
380
(606)
73
2017
8,012
(219)
(1,990)
5,803
5,173
214
991
(542)
(33)
Change
(3,551)
% Ch.
(35.6)
(2,643)
(23.5)
(20.4)
20.4
(112.6)
(3.0)
(2,210)
111
(428)
(18)
(98)
8,597
11,240
5,803
(2,643)
(23.5)
The adjusted operating profit of €8,597 million decreased by
24% compared to the full year of 2018. Excluding the impact of
the loss of control over Eni Norge which occurred at the end of
2018 to allow a-like-for-like comparison, and net of scenario
effects, accounting for a lower time value of the money
and IFRS 16, the adjusted operating profit increased by 5%
leveraging production growth in the E&P segment and steady
G&P results. The disclosure of adjusted operating profit by
segment is provided under the paragraph “Results by business
segments”.
Finance income (expense)
Finance income (expense) related to net borrowings
- Finance expense on short and long-term debt
- Interest expense for lease liabilities
- Interest from banks
- Net income from financial activities held for trading
- Interest and other income from receivables and securities for non-financing operating activities
Income (expense) on derivative financial instruments
- Derivatives on exchange rate
- Derivatives on interest rate
Exchange differences, net
Other finance income (expense)
- Interst and other income from receivables and securities for financing operating activities
- Finance expense due to the passage of time (accretion discount)
- Other finance income (expense)
Finance expense capitalized
(€ million)
2019
(962)
(740)
(378)
21
127
8
(14)
9
(23)
250
(246)
112
(255)
(103)
(972)
93
(879)
2018
(627)
(685)
2017
(834)
(751)
18
32
8
(307)
(329)
22
341
(430)
132
(249)
(313)
(1,023)
52
(971)
12
(111)
16
837
809
28
(905)
(407)
128
(264)
(271)
(1,309)
73
(1,236)
Change
(335)
(55)
(378)
3
95
293
338
(45)
(91)
184
(20)
(6)
210
51
41
92
Net finance expenses were €879 million, an improvement of €92
million from 2018. The main drivers of this reduction were: (i)
positive change of fair-valued currency derivatives (up by €338
million), lacking the formal criteria to be designated as hedges
under IFRS 9, partly offset by the exchange rate differences
(down by €91 million); (ii) reduction of other finance expense,
reflecting the circumstance that in 2018 was reported the
write-off of a financing receivables related to an unsuccessful
exploration initiative executed by a joint venture in the Black Sea
(approximately €270 million); and (iii) recognition of incomes on
exchange rate realized through capital reimbursement by certain
subsidiaries with currency other than Euro. These positives were
partly offset by the recognition of finance expenses for lease
liabilities (€378 million).
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEWEni Annual Report 2019
70
Income (expense) from investments
2019
Share of gains (losses) from equity-accounted investments
Dividends
Net gains (losses) on disposals
Other income (expense), net
(€ million)
Exploration
& Production
7
197
17
221
Gas &
Power
(11)
15
4
Refining
& Marketing
and Chemicals
(63)
50
2
Corporate and
other activities
(21)
(11)
(21)
Group
(88)
247
19
15
193
Net income from investments amounted to €193 million related to:
- dividends of €247 million paid by minor investments in certain
entities which were designated at fair value through OCI under
IFRS 9 except for dividends which are recorded through profit.
These entities mainly comprised Nigeria LNG (€186 million) and
Saudi European Petrochemical Co. (€46 million);
- (ii) a loss of €88 million recorded at equity-accounted
investments, mainly in the downstream business. These share of
profits at equity-accounted investments included the contribution
of the upstream joint venture Vår Energi (€49 million).
The table below sets forth a breakdown of net income/loss from investments:
Share of gains (losses) from equity-accounted investments
Dividends
Net gains (losses) on disposals
Other income (expense), net
Income (expense) from investments
(€ million)
2019
(88)
247
19
15
193
2018
(68)
231
22
910
1,095
2017
(267)
205
163
(33)
68
Change
(20)
16
(3)
(895)
(902)
Income from investments decreased by €902 million from 2018
due to the fact that the 2018 financial statements accounted for
the gains on the Vår Energi business combination (€889 million)
and a reversal of a prior-year impairment loss of €262 million
made at the Angola LNG equity-accounted entity in the E&P
segment.
Income taxes
Income taxes decreased by €379 million to €5,591 million mainly
due to the decrease of profit before income taxes (down by €4,361
million from 2018). The reported tax rate was 97% compared to
59% reported in 2018, reflecting a higher share of taxable incomes
reported by the Exploration & Production segment in Countries
subject to higher-than-average tax rates, lower reselling margins
on volumes of gas entitlements of a Libyan partner, while taxable
losses were incurred in jurisdictions with a lower-than average
statutory tax rate. The Group tax rate was also impacted by the write-
off of Italian deferred tax assets of approximately €0.9 billion due to
projections of lower future taxable profit at Italian subsidiaries.
Adjusted tax rate was 64%, increased from 2018 (56%), affected by
a higher tax rate in the E&P segment (approximately 6 percentage
point) due to the same drivers related to the reported tax rate.
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEW
71
Results by business segments1
Exploration & Production
Operating profit (loss)
Exclusion of special items:
- environmental charges
- impairment losses (impairment reversals), net
- net gains on disposal of assets
- provision for redundancy incentives
- risk provisions
- exchange rate differences and derivatives
- other
Adjusted operating profit (loss)
Net finance (expense) income(a)
Net income (expense) from investments(a)
Income taxes(a)
Tax rate (%)
Adjusted net profit (loss)
Results also include:
Exploration expenses:
- prospecting, geological and geophysical expenses
- write-off of unsuccessful wells(b)
Average realizations
Liquids(c)
Natural gas
Hydrocarbons
(€ million)
2019
7,417
1,223
32
1,217
(145)
23
(18)
14
100
8,640
(362)
312
(5,154)
60.0
3,436
489
275
214
($/bbl)
($/kcf)
($/boe)
59.26
4.94
43.54
2018
10,214
636
110
726
(442)
26
360
(6)
(138)
10,850
(366)
285
(5,814)
54.0
4,955
380
287
93
65.47
5.20
47.48
2017
7,651
(2,478)
46
(154)
(3,269)
19
366
(68)
582
5,173
(50)
408
(2,807)
50.8
2,724
525
273
252
50.06
3.69
35.06
Change
(2,797)
% Ch.
(27.4)
(2,210)
4
27
660
6.0
(1,519)
109
(12)
121
(6.21)
(0.26)
(3.94)
(20.4)
(30.7)
28.7
(4.2)
130.1
(9.5)
(5.0)
(8.3)
(a) Excluding special items.
(b) Also includes write-off of unproved exploration rights, if any, related to projects with negative outcome.
(c) Includes condensates.
In 2019, the Exploration & Production segment reported an adjusted
operating profit of €8,640 million down by 20% from the full year
of 2018, up by 7% excluding from the comparative period: (i) the
contribution from the former subsidiary Eni Norge which was merged
with Point Resources to establish Vår Energi, an equity-accounted
joint venture, fully operational since January 1, 2019; (ii) the IFRS 16
accounting effects; (iii) the negative trading environment which was
driven by a moderate decline of crude oil prices in dollars (the marker
Brent was down by 9%) and materially lower gas prices due to a global
oversupply and a decline in the Asian demand driving a decrease of
34% of the spot price in Italy, the main reference price for sales in the
European markets, and a decrease of 19% of the Henry Hub, while the
appreciation of USD/EUR exchange rate (up by 5%); (iv) the impact
of a flattening yield curve which increased the present value of the
assets retirement costs resulting in higher amortization charges
through profit estimated in €200 million. Particularly, a negative
impact of the trading environment (€2.23 billion) mainly due to lower
prices of equity gas as well as lower reselling margins of Libyan gas
volumes due a partner, which were marketed in Europe. The above-
mentioned lower margin is excluded by the calculation of Eni’s average
realized gas prices, because the realized prices are calculated only
with reference to equity production. The positive performance was
driven by a better volume/mix effect reflecting higher contribution of
barrels with higher-than-average profitability, partly offset by higher
write-off expenses related to unsuccessful exploration wells.
Operating profit included the result relating to certain hydrocarbon
volumes, comprised in the production for the period, whereby the
price was paid by the buyer without lifting the underlying volume
due to the take-or-pay clause in a long-term supply agreement.
Management has ascertained that it is highly likely that the buyer will
not redeem its contractual right to lift the pre-paid volumes in future
reporting periods within the contractual terms.
Adjusted operating profit excluded special items of €1,223 million.
Adjusted net profit of €3,436 million decreased by 31% due to
decreased operating profit. Gains from equity-accounted investments
included the share of the result of the joint venture Vår Energi (€122
million) and the dividends of Nigeria LNG (€186 million), partially
offset by losses from joint ventures in Venezuela.
The y-o-y net profit comparison is affected by the circumstance that
in 2018 was reported the write-off of a financing receivables related
to an unsuccessful exploration initiative executed by a joint venture in
the Black Sea.
The increase of the adjusted tax rate of 6 percentage points was due
to a higher share of taxable profit reported in Countries with higher
taxation. Cash tax rate amounted to 30%.
(1) Other alternative performance indicators disclosed are accompanied by explanatory notes and tables in line with guidance provided by ESMA guidelines on alternative performance
measures (ESMA/2015/1415), published on October 5, 2015. For further information, see the section “Alternative performance measures” of this Annual Report at subsequent pages.
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEWEni Annual Report 2019
72
Gas & Power
Operating profit (loss)
Exclusion of special items:
- impairment losses (impairment reversals), net
- environmental charges
- provision for redundancy incentives
- commodity derivatives
- exchange rate differences and derivatives
- other
Adjusted operating profit (loss)
- Gas & LNG Marketing and Power
- Eni gas e luce
Net finance (expense) income(a)
Net income (expense) from investments(a)
Income taxes(a)
Tax rate (%)
Adjusted net profit (loss)
(a) Excluding special items.
(€ million)
2019
699
(45)
37
4
(423)
92
245
654
376
278
(23)
(11)
(194)
31.3
426
2018
629
(86)
(71)
(1)
122
(156)
112
(92)
543
342
201
(4)
9
(238)
43.4
310
2017
75
139
(146)
38
157
(171)
261
214
77
137
10
(9)
(163)
75.8
52
Change
70
% Ch.
11.1
111
34
77
(19)
(20)
44
(12.1)
116
20.4
9.9
38.3
37.4
In 2019, the Gas & Power segment reported an adjusted operating
profit of €654 million, up by 20% from the full year of 2018. The
result was driven by the wholesale business performance, mainly
reflecting the contribution of optimizations at the gas and power
assets portfolio in Europe which benefitted of a highly-volatile
environment. These positives were partly offset by the weaker
LNG business result due to a lower pricing environment in Asia
which affected margins and volumes. The retail business reported
a remarkable performance improvement, leading to a 38% increase
in operating profit y-o-y, driven by more effective commercial
initiatives, higher extra-commodity revenues and lower expenses.
Adjusted operating profit excluded special items of €45 million.
Adjusted net profit was €426 million, improving by 37% from the
full year of 2018 due to increased operating profit.
Adjusted tax rate reflected a normalization at 31%, decreasing
compared to 43% in 2018 which was penalized by a higher impact
of certain non-Italian subsidiaries tax rate.
Refining & Marketing and Chemicals
Operating profit (loss)
Exclusion of inventory holding (gains) losses
Exclusion of special items:
- environmental charges
- impairment losses (impairment reversals), net
- net gains on disposal of assets
- risk provisions
- provision for redundancy incentives
- commodity derivatives
- exchange rate differences and derivatives
- other
Adjusted operating profit (loss)
- Refining & Marketing
- Chemicals
Net finance (expense) income(a)
Net income (expense) from investments(a)
Income taxes (a)
Tax rate (%)
Adjusted net profit (loss)
(a) Excluding special items.
(€ million)
2019
(854)
(318)
1,124
244
922
(5)
(2)
8
(16)
2
(29)
(48)
220
(268)
(11)
37
(53)
..
(75)
2018
(380)
234
526
193
193
(9)
21
8
23
1
96
380
390
(10)
11
(2)
(151)
38.8
238
2017
981
(213)
223
136
54
(13)
(6)
(11)
(9)
72
991
531
460
5
19
(352)
34.7
663
Change
(474)
% Ch.
..
(428)
(170)
(258)
(22)
39
98
..
(313)
..
(43.6)
..
..
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEW
73
In 2019, the Refining & Marketing business reported an adjusted
operating profit of €220 million, down by 44% y-o-y. The lower
performance from the comparative period was due by deteriorated
refining scenario mainly driven by narrowed price differentials
between heavy crudes and the Brent market benchmark, as well
as by lower products spreads, particularly lubricants, and by the
unavailability of some plants.
The decline in the refining results was partly offset by a strong
marketing performance.
In 2019 the Chemical business, reporting an adjusted operating
losses of €268 million, was negatively affected by a depressed
trading environment due to a slowdown in demand from the
main end-markets, particularly the automotive sector, and
by weaker demand of single-use plastics. Furthermore, in a
shrinking global market, the downward margins trend was
exacerbated by rising competitive pressure from producers
with lower feedstock costs (e.g., US producers using ethane-
based crackers). These drivers determined unprofitable
spreads between product prices and feedstock costs mainly
for polyethylene and a profitability decline at styrenics and
elastomers. Finally, the operating performance was also
negatively affected by the incident that occurred at the Priolo
hub, which was fully operational by the end of July, and by other
unplanned shutdowns.
Adjusted operating profit of the R&M and Chemicals segment
excluded special items of €1,124 million.
On a net basis, the negative result of €75 million reflects the lower
operating performance.
Corporate and other activities
Operating profit (loss)
Exclusion of special items:
- environmental charges
- impairment losses (impairment reversals), net
- net gains on disposal of assets
- risk provisions
- provision for redundancy incentives
- other
Adjusted operating profit (loss)
Net finance (expense) income(a)
Net income (expense) from investments(a)
Income taxes(a)
Adjusted net profit (loss)
(a) Excluding special items.
(€ million)
2019
(710)
86
62
12
(1)
23
10
(20)
(624)
(525)
43
222
(884)
2018
(691)
85
23
18
(1)
(1)
(1)
47
(606)
(697)
5
333
(965)
2017
(668)
126
26
25
(1)
82
(2)
(4)
(542)
(699)
22
178
(1,041)
Change
(19)
% Ch.
(2.7)
(18)
172
38
(111)
81
(3.0)
24.7
..
(33.3)
8.4
The results of Corporate and other activities mainly include costs
of Eni’s headquarters net of services charged to operational
companies for the provision of general purposes services,
administration, finance, information technology, human resources
management, legal affairs, international affairs, as well as
operational costs of decommissioning activities pertaining to
certain businesses which Eni exited, divested or shut down in
past years, net of the margins of captive subsidiaries providing
specialized services to the business (insurance, financial,
recruitment).
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEWEni Annual Report 2019
74
SUMMARIZED GROUP BALANCE SHEET
The summarized Group balance sheet aggregates the amount of
assets and liabilities derived from the statutory balance sheet in
accordance with functional criteria which considers the enterprise
conventionally divided into the three fundamental areas focusing
on resource investments, operations and financing. Management
believes that this summarized group balance sheet is useful
information in assisting investors to assess Eni’s capital structure
and to analyse its sources of funds and investments in fixed assets
and working capital. Management uses the summarized group
balance sheet to calculate key ratios such as the return on invested
capital (adjusted ROACE) and the financial soundness/equilibrium
(gearing and leverage).
Summarized Group Balance Sheet(a)
Fixed assets
Property, plant and equipment
Right of use
Intangible assets
Inventories - Compulsory stock
Equity-accounted investments and other investments
Receivables and securities held for operating purposes
Net payables related to capital expenditure
Net working capital
Inventories
Trade receivables
Trade payables
Net tax assets (liabilities)
Provisions
Other current assets and liabilities
Provisions for employee benefits
Assets held for sale including related liabilities
CAPITAL EMPLOYED, NET
Eni shareholders' equity
Non-controlling interest
Shareholders’ equity
Net borrowings before lease liabilities ex IFRS 16
Lease liabilities
- of which Eni working interest
- of which Joint operators' working interest
Net borrowings post lease liabilities ex IFRS 16
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY
Leverage before lease liability ex IFRS 16
Leverage after lease liability ex IFRS 16
Gearing before lease liability ex IFRS 16
Gearing after lease liability ex IFRS 16
December 31,
2019
Impact of IFRS16
adoption as of
January 1, 2019
December 31,
2018
(€ million)
62,192
5,349
3,059
1,371
9,964
1,234
(2,235)
80,934
4,734
8,519
(10,480)
(1,594)
(14,106)
(1,864)
(14,791)
(1,136)
18
65,025
47,839
61
47,900
11,477
5,648
3,672
1,976
17,125
65,025
0.24
0.36
0.18
0.26
5,643
5,643
128
(12)
116
5,759
5,759
3,730
2,029
5,759
5,759
60,302
3,170
1,217
7,963
1,314
(2,399)
71,567
4,651
9,520
(11,645)
(1,364)
(11,626)
(860)
(11,324)
(1,117)
236
59,362
51,016
57
51,073
8,289
8,289
59,362
0.16
n.a.
0.14
n.a.
Change
1,890
5,349
(111)
154
2,001
(80)
164
9,367
83
(1,001)
1,165
(230)
(2,480)
(1,004)
(3,467)
(19)
(218)
5,663
(3,177)
4
(3,173)
3,188
5,648
3,672
1,976
8,836
5,663
(a) For a reconciliation to the statutory statement of cash flow see the paragraph “Reconciliation of Summarized Group Balance Sheet and Statement of Cash Flows to Statutory Schemes”.
Fixed assets (€80,934 million) increased by €9,367 million
from December 31, 2018 mainly due to the initial recognition of
the right-of-use asset for €5,643 million following the adoption
of IFRS 16, since January 1, 2019, as well as the accounting
of the acquisition of a 20% interest in ADNOC Refining (€2.9
billion). Furthermore, the increase in property, plant and
equipment (up by €1,890 million) was due to capex incurred in
the year (€8,376 million), foreign currency translation effects
and upward revisions of the ARC (Asset Retirement Cost)
reflecting lowered discount rates. These increases were partly
offset by depreciation, depletion, amortization, impairments
and write-offs (€10,594 million).
Net working capital was in negative territory at minus €14,791
million decreased by €3,467 million y-o-y driven by higher
provisions for asset retirement obligations, increased tax
payables due to the recognition of income taxes in the period,
as well as an increase in other current liabilities, mainly due to
trade advances cashed from Egyptian partners in relation to
the progress in the development of the Zohr project.
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEW
COMPREHENSIVE INCOME
Net profit (loss)
Items that are not reclassified to profit or loss in later periods
Remeasurements of defined benefit plans
Change in the fair value of minor investments with effects to other comprehensive income
Share of "Other comprehensive income" on equity accounted investments
in relation to remeasurements of defined benefit plans
Taxation
Items that may be reclassified to profit or loss in later periods
Currency translation differences
Change in the fair value of cash flow hedging derivatives
Share of "Other comprehensive income" on equity accounted investments
Taxation
Total other items of comprehensive income (loss)
Total comprehensive income (loss)
attributable to:
- Eni's shareholders
- Non-controlling interest
CHANGES IN SHAREHOLDERS' EQUITY
(€ million)
Shareholders' equity at January 1, 2018
Total comprehensive income (loss)
Dividends distributed to Eni's shareholders
Dividends distributed by consolidated subsidiaries
Other changes
Total changes
Shareholders' equity at December 31, 2018
attributable to:
- Eni's shareholders
- Non-controlling interest
Shareholders' equity at December 31, 2018
Impact of adoption IAS 28
Shareholders' equity at January 1, 2019
Total comprehensive income (loss)
Dividends distributed to Eni's shareholders
Dividends distributed by consolidated subsidiaries
Buy-back program
Reimbursement to third party shareholders
Other changes
Total changes
Shareholders' equity at December 31, 2019
attributable to:
- Eni's shareholders
- Non-controlling interest
75
(€ million)
2019
155
(47)
(42)
(3)
(7)
5
116
604
(679)
(6)
197
69
224
217
7
2018
4,137
(2)
(15)
15
(2)
1,578
1,787
(243)
(24)
58
1,576
5,713
5,702
11
5,713
(2,953)
(3)
(8)
224
(3,018)
(4)
(400)
(1)
30
48,324
2,749
51,073
51,016
57
51,073
(4)
51,069
(3,169)
47,900
47,839
61
Shareholders’ equity including non-controlling interest was
€47,900 million, down by €3,173 million compared to December
31, 2018. Net profit for the year (€155 million) and the increase
in foreign currency translation differences (€604 million) were
offset by the remuneration of Eni’s shareholders (€3,018 million),
a negative change in the fair value of the cash flow hedge reserve
(-€679 million) as well as the impact of the share buy-back
(-€400 million).
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEWEni Annual Report 2019
76
LEVERAGE AND NET BORROWINGS
Leverage is a measure used by management to assess the
Company’s level of indebtedness. It is calculated as a ratio of
net borrowings which is calculated by excluding cash and cash
equivalents and certain very liquid assets from financial debt to
shareholders’ equity, including non-controlling interest. Gearing
measures how much of capital employed net is financed recurring
to third-party funding and is calculated as the ratio between net
borrowings and capital employed net. Management periodically
reviews leverage in order to assess the soundness and efficiency
of the Group balance sheet in terms of optimal mix between net
borrowings and net equity, and to carry out benchmark analysis
with industry standards.
Total finance debt
- Short-term debt
- Long-term debt
Cash and cash equivalents
Securities held for trading
Financing receivables held for non-operating purposes
Net borrowings before lease liabilities ex IFRS 16
Lease Liabilities
- of which Eni working interest
- of which Joint operators' working interest
Net borrowings post lease liabilities ex IFRS 16
Shareholders' equity including non-controlling interest
Leverage before lease liability ex IFRS 16
Leverage after lease liability ex IFRS 16
Gearing before lease liability ex IFRS 16
Gearing after lease liability ex IFRS 16
(€ million) December 31, 2019 December 31, 2018
25,865
5,783
20,082
(10,836)
(6,552)
(188)
8,289
24,518
5,608
18,910
(5,994)
(6,760)
(287)
11,477
5,648
3,672
1,976
17,125
47,900
0.24
0.36
0.18
0.26
8,289
51,073
0.16
n.a.
0.14
n.a.
Change
(1,347)
(175)
(1,172)
4,842
(208)
(99)
3,188
5,648
3,672
1,976
8,836
(3,173)
(0.08)
0.04
Net borrowings at December 31, 2019 were €17,125 million,
increased by €8,836 million from 2018.
Total finance debt of €24,518 million consisted of €5,608 million
of short-term debt (including the portion of long-term debt due
within twelve months of €3,156 million) and €18,910 million of
long-term debt.
This increase was driven by the initial recognition of the lease
liabilities upon the adoption of IFRS 16, which amounted to €5,759
million and included the reclassification of €128 million for certain
trade payables due in connection with the hiring of assets, which
were outstanding as of January 1, 2019. The effect of the adoption of
IFRS 16 on the Group net borrowings totalled approximately €1,976
million, driven by lease liabilities pertaining to joint operators in Eni-
led upstream unincorporated joint ventures, which will be recovered
through a partner-billing process.
Excluding the overall impact of the adoption of IFRS 16, net
borrowings were re-determined at €11,477 million, increasing by
€3,188 million compared to December 31, 2018. This increase was
mainly driven by the acquisition of a 20% interest in Adnoc Refining
and other non-organic investments.
As of December 31, 2019, the ratio of net borrowings to
shareholders’ equity including non controlling interest – leverage2
– was 0.36 due to the increase in net borrowings driven by the
adoption of IFRS 16. The impact of the lease liability pertaining to
joint operators in Eni-led upstream unincorporated joint ventures
weighted on leverage for approximately 4 points. Excluding
altogether the impact of IFRS 16, leverage would be 0.24.
As of December 31, 2019, gearing – the ratio of net borrowings to
net capital employed – was 0.26. Excluding altogether the impact of
IFRS 16, gearing would be 0.18 (0.14 at December 31, 2018).
(2) Non-GAAP financial measures and other alternative performance indicators disclosed throughout this press release are accompanied by explanatory notes and tables in line with
guidance provided by ESMA guidelines on alternative performance measures (ESMA/2015/1415), published on October 5, 2015. For further information, see the section “Non-GAAP
measures” of this press release at the subsequent pages.
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEW
77
SUMMARIZED GROUP CASH FLOW STATEMENT
Eni’s Summarized Group Cash Flow Statement derives from
the statutory statement of cash flows. It enables investors to
understand the connection existing between changes in cash
and cash equivalents (deriving from the statutory cash flows
statement) and in net borrowings (deriving from the summarized
cash flow statement) that occurred in the reporting period. The
measure which links the two statements is represented by the
“free cash flow” which is calculated as difference between the
cash flow generated from operations and the net cash used in
investing activities. Starting from free cash flow it is possible to
determine either: (i) changes in cash and cash equivalents for the
period by adding/deducting cash flows relating to financing debts/
receivables (issuance/repayment of debt and receivables related
to financing activities), shareholders’ equity (dividends paid, net
repurchase of own shares, capital issuance) and the effect of
changes in consolidation and of exchange rate differences;
and (ii) change in net borrowings for the period by adding/
deducting cash flows relating to shareholders’ equity and
the effect of changes in consolidation and of exchange rate
differences.
Summarized Group Cash Flow Statement(a)
Net profit (loss)
Adjustments to reconcile net profit (loss) to net cash provided by operating activities:
- depreciation, depletion and amortization and other non monetary items
- net gains on disposal of assets
- dividends, interests, taxes and other changes
Changes in working capital related to operations
Dividends received by investments
Taxes paid
Interests (paid) received
Net cash provided by operating activities
Capital expenditure
Investments and purchase of consolidated subsidiaries and businesses
Disposals of consolidated subsidiaries, businesses, tangible and intangible assets and investments
Other cash flow related to capital expenditure, investments and disposals
Free cash flow
Borrowings (repayment) of debt related to financing activities
Changes in short and long-term financial debt
Repayment of lease liabilities
Dividends paid and changes in non-controlling interests and reserves
Effect of changes in consolidation, exchange differences and cash
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENT
Change in net borrowings
Free cash flow
Repayment of lease liabilities
Net borrowings of acquired companies
Net borrowings of divested companies
Exchange differences on net borrowings and other changes
Dividends paid and changes in non-controlling interest and reserves
CHANGE IN NET BORROWINGS BEFORE LEASE LIABILITIES
IFRS 16 first application effect
Repayment of lease liabilities
New leases subscription of the period and other changes
Change in lease liabilities
CHANGE IN NET BORROWINGS AFTER LEASE LIABILITIES
(€ million)
2019
155
2018
4,137
2017
3,377
Change
(3,982)
10,480
7,657
8,720
2,823
(170)
6,224
366
1,346
(474)
(3,446)
6,168
1,632
275
3,650
1,440
291
(5,068)
(5,226)
(3,437)
(941)
(522)
(478)
304
56
(1,266)
1,071
158
(419)
12,392
13,647
10,117
(1,255)
(8,376)
(9,119)
(8,681)
743
(3,008)
504
(254)
1,258
(279)
(1,540)
(877)
(244)
1,242
942
6,468
(357)
(510)
5,455
(373)
(2,764)
(738)
(1,196)
6,008
(5,210)
341
78
320
(1,712)
(1,860)
(3,424)
(2,957)
(2,883)
1
18
(65)
(877)
(467)
(17)
(4,861)
3,492
1,689
(8,353)
(€ million)
2019
1,258
(877)
13
(158)
2018
6,468
(18)
(499)
(367)
2017
6,008
261
474
Change
(5,210)
(877)
18
512
209
(3,424)
(2,957)
(2,883)
(467)
(3,188)
(5,759)
877
(766)
(5,648)
(8,836)
2,627
3,860
(5,815)
(5,759)
877
(766)
(5,648)
2,627
3,860 (11,463)
(a) For a reconciliation to the statutory statement of cash flow see the paragraph “Reconciliation of Summarized Group Balance Sheet and Statement of Cash Flows to Statutory Schemes”.
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEWEni Annual Report 2019
78
Net cash provided by operating activities amounted to €12,392
million in the full year 2019 and included dividends paid to Eni
by joint ventures, affiliates and other minority interests (€1,346
million) integrated with Eni’s strategy and development plans.
The main amount was paid by the JV Vår Energi for €1,057
million. The amount of trade receivables due in subsequent
reporting periods divested to financing institutions was almost
unchanged from FY 2018 (€1,782 million).
Net cash before changes in working capital at replacement cost
and excluding extraordinary credit provisions (€0.3 billion) was
€12.1 billion, slightly decreasing from the full year of 2018 (down
by 4%), despite a markedly unfavourable scenario. Following the
adoption of IFRS 16, net cash provided by operating activities
improved by €666 million because the reimbursement of the
principal of lease fees pertaining to assets hired in connection
to operating activities are no longer part of the operating cash
outflows, but are now part of the cash flow from financing activities.
Cash outflows for capital expenditures and investments were
€11,384 million, including the consideration for the acquisition
of a 20% interest in ADNOC Refining (€2.9 billion) and cash-
outs for the acquisition of hydrocarbons reserves in Alaska
and Algeria and other non-organic items for an overall amount
of €0.4 billion. Net of the above mentioned non-organic items
and of trade advances cashed by Egyptian partners in relation
to the financing of the Zohr project (€0.3 billion), capital
expenditures amounted to €7.73 billion.
Following the adoption of IFRS 16, these cash outflows improved
by €211 million because the reimbursement of the principal of
lease fees, which are incurred in relation to the hire of equipment
used in connection with a capital project, are no longer recognized
as cash outflows of investing activities, but are now part of the
cash flow from financing activities.
The free cash flow benefitted from a favorable €877 million effect
due to the adoption of IFRS 16.
2019 Full Year
(€ million)
Net cash before changes in working capital at replacement cost(a)
Changes in working capital at replacement cost(a)
Net cash provided by operating activities
Capital expenditure
Free cash flow
Cash flow from financing activity
Net increase (decrease) in cash and cash equivalent
After IFRS 16
adoption
11,803
589
12,392
(8,376)
1,258
(5,841)
(4,861)
Provisions for
extraordinary
credit and other
charges
336
(336)
Adjusted
after IFRS 16
adoption
12,139
253
IFRS 16
impact
(695)
29
(666)
(211)
(877)
877
Before IFRS
16 adoption
11,444
282
11,726
(8,587)
381
(4,964)
(4,861)
(a) Excluding from changes in working capital as reported in the cash flow statement (€366 million) the increase in stock profit due to price effect amounting to €223 million
and provisions for extraordinary credit and other charges of €336 million (€366 million + €223 million - €336 million = €253 million). Consistently, net cash before changes in
working capital at replacement cost excludes the stock profit and provisions for extraordinary credit and other charges.
The line item Dividends paid and other changes in non-
controlling interests and reserves (€3,424 million) related
mainly to the payment of dividends to Eni’s shareholders (€3,018
million including the 2018 balance dividend and the 2019 interim
dividend) and to the repurchase of own shares (€400 million) in
line with the buyback program adopted by management as part
of the authorization set by Eni’s Shareholders Meeting on May 14,
2019, which envisaged a maximum cash out of €400 million and
up to 67 million shares for the year 2019.
In the FY 2019, net cash provided by operating activities financed
the cash outflows related to organic investments, net of trade
advances cashed by Egyptian partners in relation to the financing
of the Zohr project which resulted in a positive free cash flow
of approximately €4.3 billion. This discretional cash amount
was utilized to entirely fund the shareholders’ remuneration of
€3.4 billion, determining, with equity and reserves acquisitions
(€3.3 billion) and disposals of €0.5 billion, an increase of net
borrowings before IFRS 16 impacts by approximately €3.2 billion
also including the payment of lease liabilities (approximately €0.9
billion). The organic capex for the FY and the dividend were funded
with the operating cash flow before IFRS 16 effects at the Brent
scenario of 55 $/bbl and assuming the budget scenario for gas
prices and refining margins, or 50 $/bbl after IFRS 16 effects. At
the current scenario, the cash neutrality came at 64 $/bbl before
IFRS 16 effects (59 $/bbl after IFRS 16).
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEW
79
Capital expenditure
Exploration & Production
- acquisition of proved and unproved properties
- exploration
- development
- other expenditure
Gas & Power
Refining & Marketing and Chemicals
- Refining & Marketing
- Chemical
Corporate and other activities
Impact of unrealized intragroup profit elimination
Capital expenditure
(€ million)
2019
6,996
400
586
5,931
79
230
933
815
118
231
(14)
8,376
2018
7,901
869
463
6,506
63
215
877
726
151
143
(17)
9,119
2017
7,739
5
442
7,236
56
142
729
526
203
87
(16)
8,681
Change
(905)
(469)
123
(575)
16
15
56
89
(33)
88
% Ch.
(11.5)
(54.0)
26.6
(8.8)
25.4
7.0
6.4
12.3
(21.9)
61.5
(743)
(8.1)
In the full year of 2019, capital expenditure amounted to €8,376
million (€9,119 million in the FY 2018) and mainly related to:
- development activities (€5,931 million) deployed mainly in
Egypt, Nigeria, Kazakhstan, Indonesia, Mexico, the USA and
Angola. The acquisition of proved and unproved reserves of
€400 million relates to the acquisition of reserves in Alaska
and Algeria;
- refining activity in Italy and outside Italy (€683 million) mainly
aimed at reconstruction works of the EST conversion plant at
the Sannazzaro refinery, reconversion of Gela refinery, maintain
plants’ integrity as well as initiatives in the field of health,
security and environment; marketing activity, mainly regulation
compliance and stay in business initiatives in the refined product
retail network in Italy and in the Rest of Europe (€132 million);
initiatives relating to gas marketing (€176 million).
-
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEWEni Annual Report 2019
80
Alternative performance measures (Non-GAAP measure)
Management evaluates underlying business performance on the
basis of Non-GAAP financial measures under IFRS (“Alternative
performance measures”), such as adjusted operating profit and
adjusted net profit, which are arrived at by excluding inventory
holding gains or losses, special items and, in determining the
business segments’ adjusted results, finance charges on finance
debt and interest income. From 2017, the recognition of the
inventory holding (gains) losses has been revised in the Gas &
Power segment considering a recently-enacted, less restrictive
regulatory framework relating the legal obligation on part of
gas wholesalers to retain gas volumes in storage to ensure an
adequate level of modulation to the retail segment. On this basis,
management has progressively reduced gas quantities held in
storage and has commenced to leverage those quantities to
improve margins by seeking to capture the seasonality in gas
prices existing between the phase of gas injection (which typically
occurs in summer months) vs. the phase of gas off-take (which
typically occurs during the winter months). Therefore, from the
closure of the statutory period of gas injection, i.e. from the fourth
quarter of 2017, the determination of the stock profit or loss in the
Gas & Power segment has changed and currently gas off-takes
from storage are valued at the average cost incurred during the
injection period net of the effects of hedging derivatives, ensuring
when the purchased volumes are matched by the corresponding
sales (net of the effects of hedging derivatives) the proper
measurement and accountability of the economic performances.
The adjusted operating profit of each business segment reports
gains and losses on derivative financial instruments entered
into to manage exposure to movements in foreign currency
exchange rates, which affect industrial margins and translation of
commercial payables and receivables. Accordingly, also currency
translation effects recorded through profit and loss are reported
within business segments’ adjusted operating profit. The taxation
effect of the items excluded from adjusted operating or net profit
is determined based on the specific rate of taxes applicable to
each of them. Management includes them in order to facilitate a
comparison of base business performance across periods, and
to allow financial analysts to evaluate Eni’s trading performance
on the basis of their forecasting models. Non-GAAP financial
measures should be read together with information determined by
applying IFRS and do not stand in for them. Other companies may
adopt different methodologies to determine Non-GAAP measures.
Follows the description of the main alternative performance
measures adopted by Eni. The measures reported below refer to
the performance of the reporting periods disclosed in this press
release.
Adjusted operating and net profit
Adjusted operating and net profit are determined by excluding
inventory holding gains or losses, special items and, in
determining the business segments’ adjusted results, finance
charges on finance debt and interest income. The adjusted
operating profit of each business segment reports gains and
losses on derivative financial instruments entered into to manage
exposure to movements in foreign currency exchange rates which
impact industrial margins and translation of commercial payables
and receivables. Accordingly, also currency translation effects
recorded through profit and loss are reported within business
segments’ adjusted operating profit. The taxation effect of the
items excluded from adjusted operating or net profit is determined
based on the specific rate of taxes applicable to each of them.
Finance charges or income related to net borrowings excluded
from the adjusted net profit of business segments are comprised
of interest charges on finance debt and interest income earned
on cash and cash equivalents not related to operations. Therefore,
the adjusted net profit of business segments includes finance
charges or income deriving from certain segment operated assets,
i.e., interest income on certain receivable financing and securities
related to operations and finance charge pertaining to the
accretion of certain provisions recorded on a discounted basis (as
in the case of the asset retirement obligations in the Exploration &
Production segment).
Inventory holding gain or loss
This is the difference between the cost of sales of the volumes
sold in the period based on the cost of supplies of the same
period and the cost of sales of the volumes sold calculated using
the weighted average cost method of inventory accounting as
required by IFRS.
Special items
These include certain significant income or charges pertaining to
either: (i) infrequent or unusual events and transactions, being
identified as non-recurring items under such circumstances; (ii)
certain events or transactions which are not considered to be
representative of the ordinary course of business, as in the case of
environmental provisions, restructuring charges, asset impairments
or write ups and gains or losses on divestments even though
they occurred in past periods or are likely to occur in future ones.
Exchange rate differences and derivatives relating to industrial
activities and commercial payables and receivables, particularly
exchange rate derivatives to manage commodity pricing formulas
which are quoted in a currency other than the functional currency
are reclassified in operating profit with a corresponding adjustment
to net finance charges, notwithstanding the handling of foreign
currency exchange risks is made centrally by netting off naturally-
occurring opposite positions and then dealing with any residual risk
exposure in the derivative market. Finally, special items include the
accounting effects of fair-valued commodity derivatives relating to
commercial exposures, in addition to those which lack the criteria to
be designed as hedges, also those which are not eligible for the own
use exemption, including the ineffective portion of cash flow hedges,
as well as the accounting effects of commodity and exchange rates
derivatives whenever it is deemed that the underlying transaction
is expected to occur in future reporting periods. As provided for in
Decision No. 15519 of July 27, 2006 of the Italian market regulator
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEW 81
(CONSOB), non-recurring material income or charges are to be
clearly reported in the management’s discussion and financial
tables.
Leverage
Leverage is a Non-GAAP measure of the Company’s financial
condition, calculated as the ratio between net borrowings and
shareholders’ equity, including non-controlling interest. Leverage
is the reference ratio to assess the solidity and efficiency of the
Group balance sheet in terms of incidence of funding sources
including third-party funding and equity as well as to carry out
benchmark analysis with industry standards.
Gearing
Gearing is calculated as the ratio between net borrowings and
capital employed net and measures how much of capital employed
net is financed recurring to third-party funding.
Net cash provided by operating activities before changes in
working capital at replacement cost
Net cash provided from operating activities before changes in
working capital and excluding inventory holding gain or loss.
Free cash flow
Free cash flow represents the link existing between changes in
cash and cash equivalents (deriving from the statutory cash flows
statement) and in net borrowings (deriving from the summarized
cash flow statement) that occurred from the beginning of the period
to the end of period. Free cash flow is the cash in excess of capital
expenditure needs. Starting from free cash flow it is possible to
determine either: (i) changes in cash and cash equivalents for the
period by adding/deducting cash flows relating to financing debts/
receivables (issuance/repayment of debt and receivables related
to financing activities), shareholders’ equity (dividends paid, net
repurchase of own shares, capital issuance) and the effect of
changes in consolidation and of exchange rate differences; (ii)
changes in net borrowings for the period by adding/deducting cash
flows relating to shareholders’ equity and the effect of changes in
consolidation and of exchange rate differences.
Net borrowings
Net borrowings is calculated as total finance debt less cash,
cash equivalents and certain very liquid investments not related
to operations, including among others non-operating financing
receivables and securities held for trading. Financial activities are
qualified as “not related to operations” when these are not strictly
related to the business operations.
ROACE (Return On Average Capital Employed) adjusted
Is the return on average capital invested, calculated as the ratio
between net income before non-controlling interest, plus net
financial charges on net financial debt, less the related tax effect
and net average capital employed.
Coverage
Financial discipline ratio, calculated as the ratio between operating
profit and net finance charges.
Current ratio
Measures the capability of the company to repay short-term
debt, calculated as the ratio between current assets and current
liabilities.
Debt coverage
Rating companies use the debt coverage ratio to evaluate debt
sustainability. It is calculated as the ratio between net cash
provided by operating activities and net borrowings, less cash and
cash-equivalents, securities held for non-operating purposes and
financing receivables for non-operating purposes.
Net Debt/EBITDA adjusted
Net Debt/adjusted EBITDA is the ratio between the profit available to
cover the debt before interest, taxes, amortizations and impairment.
This index is a measure of the company’s ability pay off its debt and
gives an indication as to how long a company would need to operate
at its current level to pay off all its debt.
Profit per boe
Measures the return per oil and natural gas barrel produced. It is
calculated as the ratio between Results of operations from E&P
activities (as defined by FASB Extractive Activities - Oil and Gas
Topic 932) and production sold.
Opex per boe
Measures efficiency in the Oil & Gas development activities,
calculated as the ratio between operating costs (as defined
by FASB Extractive Activities - Oil and Gas Topic 932) and
production sold.
Finding & Development cost per boe
Represents Finding & Development cost per boe of new proved
or possible reserves. It is calculated as the overall amount of
exploration and development expenditure, the consideration for the
acquisition of possible and probable reserves as well as additions
of proved reserves deriving from improved recovery, extensions,
discoveries and revisions of previous estimates (as defined by FASB
Extractive Activities - Oil and Gas Topic 932).
The following tables report the group operating profit and Group
adjusted net profit and their breakdown by segment, as well as is
represented the reconciliation with net profit attributable to Eni’s
shareholders of continuing operations.
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEWEni Annual Report 2019 82
n
o
i
t
c
u
d
o
r
P
&
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o
i
t
a
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l
p
x
E
r
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w
o
P
&
s
a
G
7,417
699
(€ million)
32
1,217
(145)
(18)
23
14
100
1,223
8,640
(362)
312
(5,154)
60.0
3,436
37
4
(423)
92
245
(45)
654
(23)
(11)
(194)
31.3
426
d
n
a
g
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k
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M
&
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fi
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(854)
(318)
244
922
(5)
(2)
8
(16)
2
(29)
1,124
(48)
(11)
37
(53)
..
(75)
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h
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a
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(710)
62
12
(1)
23
10
(20)
86
(624)
(525)
43
222
d
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i
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a
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g
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t
n
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m
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(120)
95
(25)
5
(884)
(20)
P
U
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6,432
(223)
338
2,188
(151)
3
45
(439)
108
296
2,388
8,597
(921)
381
(5,174)
64.2
2,883
7
2,876
148
(157)
2,885
2,876
2019
Reported operating profit (loss)
Exclusion of inventory holding (gains) losses
Exclusion of special items:
- environmental charges
- impairment losses (impairments reversal), net
- net gains on disposal of assets
- risk provisions
- provision for redundancy incentives
- commodity derivatives
- exchange rate differences and derivatives
- other
Special items of operating profit (loss)
Adjusted operating profit (loss)
Net finance (expense) income(a)
Net income(expense) from investments(a)
Income taxes(a)
Tax rate (%)
Adjusted net profit (loss)
of which attributable to:
- non-controlling interest
- Eni's shareholders
Reported net profit (loss) attributable to Eni's shareholders
Exclusion of inventory holding (gains) losses
Exclusion of special items
Adjusted net profit (loss) attributable to Eni's shareholders
(a) Excluding special items.
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEW
n
o
i
t
c
u
d
o
r
P
&
n
o
i
t
a
r
o
l
p
x
E
r
e
w
o
P
&
s
a
G
10,214
629
(€ million)
110
726
(442)
360
26
(6)
(138)
636
10,850
(366)
285
(5,814)
54.0
4,955
(1)
(71)
122
(156)
112
(92)
(86)
543
(4)
9
(238)
43.4
310
d
n
a
g
n
i
t
e
k
r
a
M
&
s
l
a
c
i
m
e
h
C
g
n
i
n
fi
e
R
(380)
234
193
193
(9)
21
8
23
1
96
526
380
11
(2)
(151)
38.8
238
r
e
h
t
o
d
n
a
e
t
a
r
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p
r
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C
s
e
i
t
i
v
i
t
c
a
(691)
23
18
(1)
(1)
(1)
47
85
(606)
(697)
5
333
(965)
d
e
z
i
l
a
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r
n
u
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g
a
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t
n
i
n
o
i
t
a
n
m
i
i
l
e
211
(138)
73
(17)
56
2018
Reported operating profit (loss)
Exclusion of inventory holding (gains) losses
Exclusion of special items:
- environmental charges
- impairment losses (impairments reversal), net
- net gains on disposal of assets
- risk provisions
- provision for redundancy incentives
- commodity derivatives
- exchange rate differences and derivatives
- other
Special items of operating profit (loss)
Adjusted operating profit (loss)
Net finance (expense) income(a)
Net income(expense) from investments(a)
Income taxes(a)
Tax rate (%)
Adjusted net profit (loss)
of which attributable to:
- non-controlling interest
- Eni's shareholders
Reported net profit (loss) attributable to Eni's shareholders
Exclusion of inventory holding (gains) losses
Exclusion of special items
Adjusted net profit (loss) attributable to Eni's shareholders
(a) Excluding special items.
83
P
U
O
R
G
9,983
96
325
866
(452)
380
155
(133)
107
(87)
1,161
11,240
(1,056)
297
(5,887)
56.2
4,594
11
4,583
4,126
69
388
4,583
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEWEni Annual Report 2019
84
2017
Reported operating profit (loss)
Exclusion of inventory holding (gains) losses
Exclusion of special items:
- environmental charges
- impairment losses (impairments reversal), net
- net gains on disposal of assets
- risk provisions
- provision for redundancy incentives
- commodity derivatives
- exchange rate differences and derivatives
- other
Special items of operating profit (loss)
Adjusted operating profit (loss)
Net finance (expense) income(a)
Net income(expense) from investments(a)
Income taxes(a)
Tax rate (%)
Adjusted net profit (loss)
of which attributable to:
- non-controlling interest
- Eni's shareholders
Reported net profit (loss) attributable to Eni's shareholders
Exclusion of inventory holding (gains) losses
Exclusion of special items
Adjusted net profit (loss) attributable to Eni's shareholders
(a) Excluding special items.
(€ million)
r
e
w
o
P
&
s
a
G
75
d
n
a
g
n
i
t
e
k
r
a
M
&
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l
a
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i
m
e
h
C
i
g
n
n
fi
e
R
981
(213)
(146)
38
157
(171)
261
139
214
10
(9)
(163)
75.8
52
136
54
(13)
(6)
(11)
(9)
72
223
991
5
19
(352)
34.7
663
r
e
h
t
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d
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a
e
t
a
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p
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C
s
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v
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c
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(668)
26
25
(1)
82
(2)
(4)
126
(542)
(699)
22
178
d
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i
l
a
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r
n
u
f
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I
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a
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m
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(27)
(6)
(33)
17
(1,041)
(16)
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P
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a
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E
7,651
46
(154)
(3,269)
366
19
(68)
582
(2,478)
5,173
(50)
408
(2,807)
50.8
2,724
P
U
O
R
G
8,012
(219)
208
(221)
(3,283)
448
49
146
(248)
911
(1,990)
5,803
(734)
440
(3,127)
56.8
2,382
3
2,379
3,374
(156)
(839)
2,379
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEW
Reconciliation of Summarized Group Balance Sheet
and Statement of Cash Flow to Statutory Schemes
85
December 31, 2019
December 31, 2018
Notes to the
Consolidated
Financial
Statement
Amounts
from
statutory
scheme
Amounts
of the
summarized
Group
scheme
Amounts
from
statutory
scheme
Amounts
of the
summarized
Group
scheme
(€ million)
Summarized Group Balance Sheet
Items of Summarized Group Balance Sheet
(where not expressly indicated, the item derives directly
from the statutory scheme)
Fixed assets
Property, plant and equipment
Right of use
Intangible assets
Inventories - Compulsory stock
Equity-accounted investments and other investments
Receivables and securities held for operating activities
Net payables related to capital expenditure, made up of:
- receivables related to disposals
- receivables related to disposals non-current
- payables for purchase of non-current assets
Total fixed assets
Net working capital
Inventories
Trade receivables
Trade payables
Net tax assets (liabilities), made up of:
- current income tax payables
- non-current income tax payables
- other current tax liabilities
- deferred tax liabilities
- other non-current tax liabilities
- current income tax receivables
- non-current income tax receivables
- other current tax assets
- deferred tax assets
- other non-current tax assets
- payables for Italian consolidated accounts
Provisions
Other current assets and liabilities, made up of:
- short-term financial receivables for operating purposes
- receivables vs. partners for exploration and production activities and other
- other current assets
- other receivables and other assets non-current
- advances, other payables, payables vs. partners for exploration and
production activities and other
- other current liabilities
- other payables and other liabilities non-current
Total net working capital
Provisions for employee benefits
Assets held for sale including related liabilities
made up of:
- assets held for sale
- liabilities directly associated with held for sale
CAPITAL EMPLOYED, NET
Shareholders' equity including non-controlling interest
Net borrowings
Total debt, made up of:
- long-term debt
- current portion of long-term debt
- short-term debt
less:
Cash and cash equivalents
Securities held for trading
Financing receivables held for non-operating purposes
Net borrowings before lease liabilities ex IFRS 16
Lease liabilities, made up of:
- long-term lease liabilities
- current portion of long-term lease liabilities
Total net borrowings post lease liabilities ex IFRS 16(a)
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY
(a) For details on net borrowings see also note 19 to the consolidated financial statements.
(see note 16)
(see note 7)
(see note 10)
(see note 17)
30
11
(2,276)
(see note 7)
(see note 17)
(see note 10)
(see note 10)
(see note 10)
(see note 10)
(see note 17)
(see note 16)
(see note 7)
(see note 10)
(see note 10)
(see note 17)
(see note 10)
(see note 10)
(see note 16)
(456)
(454)
(1,411)
(4,920)
(63)
192
173
766
4,360
223
(4)
37
4,324
3,206
637
(2,785)
(5,735)
(1,548)
18
18,910
3,156
2,452
4,759
889
122
9
(2,530)
(440)
(287)
(1,432)
(4,272)
(34)
191
168
561
3,931
254
(4)
51
4,459
2,258
361
(2,568)
(3,980)
(1,441)
295
(59)
20,082
3,601
2,182
62,192
5,349
3,059
1,371
9,964
1,234
(2,235)
80,934
4,734
8,519
(10,480)
(1,594)
(14,106)
(1,864)
(14,791)
(1,136)
18
65,025
47,900
24,518
(5,994)
(6,760)
(287)
11,477
5,648
17,125
65,025
60,302
3,170
1,217
7,963
1,314
(2,399)
71,567
4,651
9,520
(11,645)
(1,364)
(11,626)
(860)
(11,324)
(1,117)
236
59,362
51,073
25,865
(10,836)
(6,552)
(188)
8,289
8,289
59,362
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEWEni Annual Report 2019
86
Summarized Group Cash Flow Statement
Items of Summarized Cash Flow Statement and
confluence/reclassification of items in the statutory scheme
2019
2018
(€ million)
Amounts from
statutory scheme
Amounts of the
summarized Group
scheme
Amounts from
statutory scheme
Amounts of the
summarized Group
scheme
Net profit (loss)
Adjustments to reconcile net profit (loss) to net cash provided by operating
activities:
Depreciation, depletion and amortization and other non monetary items
- depreciation, depletion and amortization
- impairment losses (impairment reversals) of tangible, intangible and right
of use, net
- write-off of tangible and intangible assets
- share of profit (loss) of equity-accounted investments
- other changes
- net change in the provisions for employee benefits
Net gains on disposal of assets
Dividends, interests, income taxes and other changes
- dividend income
- interest income
- interest expense
- income taxes
Changes in working capital related to operations
- inventories
- trade receivables
- trade payables
- provisions
- other assets and liabilities
Dividends received
Taxes paid
Interests (paid) received
- interest received
- interest paid
Net cash provided by operating activities
Investing activities
- tangible assets and prepaid for right-of-use assets
- intangible assets
Investments and purchase of consolidated subsidiaries and businesses
- investments
- consolidated subsidiaries and businesses net of cash and cash equivalent
acquired
Disposals
- tangible assets
- intangible assets
- consolidated subsidiaries and businesses net of cash and cash equivalent
disposed of
- tax on disposals
- investments
Other cash flow related to capital expenditure, investments and disposals
- investment of securities held for operating purposes
- investment of financing receivables held for operating purposes
- change in payables in relation to investing activities
- disposal of securities held for operating purposes
- disposal of financing receivables held for operating purposes
- change in receivables in relation to disposals
Free cash flow
4,137
7,657
(474)
6,168
1,632
275
(5,226)
(522)
13,647
(9,119)
(244)
1,242
942
155
10,480
(170)
6,224
366
1,346
(5,068)
(941)
12,392
(8,376)
(3,008)
504
(254)
6,988
866
100
68
(474)
109
(231)
(185)
614
5,970
15
334
642
(238)
879
87
(609)
(8,778)
(341)
(125)
(119)
1,089
5
(47)
195
(8)
(358)
408
15
279
606
8,106
2,188
300
88
(179)
(23)
(247)
(147)
1,027
5,591
(200)
1,023
(940)
272
211
88
(1,029)
(8,065)
(311)
(3,003)
(5)
264
17
187
(3)
39
(8)
(229)
(307)
17
178
95
1,258
6,468
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEW
87
2019
2018
(€ million)
Amounts from
statutory scheme
Amounts of the
summarized
Group scheme
1,258
Amounts from
statutory scheme
Amounts of the
summarized
Group scheme
6,468
continued Summarized Group Cash Flow Statement
Items of Summarized Cash Flow Statement and
confluence/reclassification of items in the statutory scheme
Free cash flow
Borrowings (repayment) of debt related to financing activities
- net change of securities and financing receivables held
for non-operating purposes
Changes in short and long-term finance debt
- Increase in long-term debt
- Repayments of long-term debt
Increase (decrease) in short-term debt
Repayment of lease liabilities
Dividends paid and changes in non-controlling interest and reserves
- reimbursement to non-controlling interest
- acquisition of treasury shares
- acquisition of additional interests in consolidated subsidiaries
- dividends paid to Eni's shareholders
- dividends paid to non-controlling interest
Effect of changes in consolidation, exchange differences
and cash equivalent
- effect of exchange rate changes and other changes on cash and cash equivalents
- effect of change in consolidation (inclusion/exclusion of significant/insignificant
subsidiaries)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENT
(279)
1,811
(3,512)
161
(1)
(400)
(1)
(3,018)
(4)
8
(7)
(279)
(1,540)
(877)
(3,424)
1
(4,861)
(357)
3,790
(2,757)
(713)
(2,954)
(3)
18
(357)
320
(2,957)
18
3,492
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEWEni Annual Report 2019
88
Risk factors
and uncertainties
The risks described below may have a material effect on our
operational and financial performance. We invite our investors to
consider these risks carefully.
Risk factors
The Company’s performance is affected by volatile prices of crude
oil and produced natural gas and by fluctuating margins on the
marketing of natural gas and on the integrated production and
marketing of refined products and chemical products
The price of crude oil is the single, largest variable that affects the
Company’s performance. Because it is a commodity business, the
price of crude oil has a history of volatility and is influenced by a
number of macro-factors that are beyond management’s control.
Crude oil prices are mainly driven by the balance between global oil
supplies and demand and hence the global levels of inventories and
spare capacity. Worldwide demand for crude oil is highly correlated to
the macroeconomic cycle. A downturn in economic activity normally
triggers lower global demand for crude oil and possibly a supply build-
up. Whenever global supplies of crude oil outstrip demand, crude
oil prices weaken. Other factors which influence demand for crude
oil are demographic growth and improving living standards, prices
and availability of alternative sources of energy (e.g., nuclear and
renewables), technological advances affecting energy efficiency,
measures which have been adopted or planned by governments
all around the world to fight global warming, including stricter
regulations and control on production and consumption of crude oil,
or a shift in consumer preferences. The push to reduce worldwide
greenhouse gas emissions and an ongoing energy transition towards
a low carbon economy, which are widely considered to be irreversible
trends, will represent in our view major trends in shaping global
demand and supplies of crude oil over the long-term and may lead to
lower crude oil demands and consumption; see the section dedicated
to the discussion of climate-related risks below. Furthermore, oil
demand is subject to several, unpredictable events. Geopolitical
tensions, local conflicts, terrorism, attacks, social instability,
widespread civil unrest, pandemic diseases could dent consumers’
confidence, economic growth and hence global demand for oil.
Historically, the OPEC cartel and lately the OPEC+ agreement, which
includes OPEC members and other important oil producers like Russia,
have exerted a big influence over global supplies of crude oil and crude
oil prices. Saudi Arabia plays a crucial role within the cartel, because it
is estimated to hold huge amounts of reserves and a vast majority of
worldwide spare production capacity. This explains why geopolitical
developments in the Middle East and particularly in the Gulf area, like
regional conflicts, acts of war, strikes, attacks, sabotages and social
and political tensions can have a big influence on crude oil prices. Also,
sanctions imposed by the USA and the EU against certain producing
Countries may influence trends in crude oil prices. However, we believe
that the resurgence of oil production in the USA due to the technology-
driven shale oil revolution has somewhat reduced the ability of
OPEC to control the global supply of oil. To a lesser extent, factors like
adverse weather conditions and operational issues at key petroleum
infrastructure can influence crude oil prices.
The price of crude oil has been on a downtrend for the last six years,
shedding more than two thirds of its value in this timeframe (from
approximately 110 $/bbl in 2014 to the current level below 30 $/bbl
as of end of March 2020). The development has been mainly driven
by a supply glut fuelled by continued grow in the production of tight
oil in the USA and the need of US independent producers to recover
their investments, at a time when the pace of increase in crude oil
demand has moderated. These trends have been exacerbated by the
adverse developments recorded in the first quarter 2020 (see below).
At the beginning of 2019, crude oil prices rebounded somewhat from
another stage of the down cycle recorded in the final part of 2018,
when the price of the Brent crude oil benchmark fell to around 50 $/
barrel (Source: Platt’s Oilgram), supported by the production cuts
implemented by the OPEC+ agreement and by production losses for
Venezuela and Iran due to geopolitical factors. Brent prices peaked at
75 $/barrel in April 2019. Then, a new downward trend commenced
pushing crude oil price down to the mid-$50 range during the summer
months of 2019. The correction was driven by a global economic
slowdown impacting fuel demand, uncertainties relating to the
developments of the United States-China trade dispute and Brexit,
and building oversupplies due to rising production levels in the United
States and elsewhere. Against this backdrop, the September 2019
air attacks against strategic oil facilities in Saudi Arabia, which were
of unprecedented reach and scale and caused a massive albeit
temporary production loss, had little effects on crude oil prices because
due to large worldwide supplies, no significant disruptions occurred in
the marketplace and after a brief spike, crude oil prices reverted to then
ongoing downtrend.
In the last part of 2019 and the beginning of 2020, crude oil prices
tried to rebound, supported by the renewal of the OPEC+ agreement
through the end of March 2020, which provided an increase of
500 kbbl/d in the production cuts to the target of 1.7 million bbl/d,
with Saudi Arabia committing itself to cut its production quota by
a further 400 kbbl/d. Other factors supportive of crude oil prices
were the resurgence of geopolitical tensions in the Gulf area, a
de-escalation in the trade dispute between the USA and China
and early signs of a strengthening global economy. As a result of
these trends, in 2019 the price for the Brent crude oil benchmark
averaged 64 $/barrel, 9% lower than in 2018.
After a solid start in 2020 with Brent prices rising up to 65 $/barrel,
crude oil prices took a hit due to a sudden drop in demand
triggered by the outbreak of a pandemic disease known as
COVID-19 spreading from China to other Countries around the
world. The sell-off intensified through February and early March
2020 as governments across the globe stepped up efforts to
contain the virus, impacting economic activity and travel. In
early March 2020, members of the OPEC+ agreement failed to
reach a deal for additional production cuts claimed by some
members to counteract the COVID-19 effects. These developments
triggered a collapse in crude oil prices. The price of the Brent
crude benchmark has fallen by more 50% from the value recorded
before the onset of the disease at more than 65 $/bbl in early
January 2020. Depending on how the current COVID-19 crisis
89
unfolds, on how long it takes to contain the virus and on the
severity of an ensuing economic downturn, as well as on future
developments regarding the willingness of the OPEC+ agreement
to support crude oil prices, the ongoing developments could
materially and negatively affect the outlook for the Company, its
results of operations, cash flow and business prospects including
shareholders' returns and the price of Eni's share.
Management expects oil demand growth to remain subdued
in 2020 and possibly to decline due to the effects of COVID-19
on global economic activity and travel. For the medium term,
management expects global oil demand to resume growing at a
rate in line with historical averages. Global crude oil supplies are
expected to grow at a moderate pace. International oil companies
are expected to retain a selective approach to investment decisions
due to cash flow considerations and also the growth rate in the
production of tight oil in the USA is expected to slow down due to
greater focus on capital discipline by US independent upstreamers.
The cohesion of OPEC+ alliance is a factor of uncertainty to the
global balance between supplies and demand.
Lower prices from one year to another negatively affect the Group’s
consolidated results of operations and cash flow. This is because
lower oil prices translate into lower revenues recognised in the
Company’s Exploration & Production segment at the time of the
price change, whereas expenses in this segment are either fixed or
less sensitive to changes in crude oil prices than revenues. Based
on the current portfolio of oil and gas assets, Eni’s management
estimates that the Company’s consolidated net cash provided
by operating activities would vary by approximately €0.15
billion for each one-dollar change in the price of the Brent crude
oil benchmark with respect to the price case assumed in Eni’s
financial projections for 2020.
The price of natural gas generally follows a trend similar to that of
crude oil, but it can also exhibit greater movements either upward
or downward. In 2019, due to a combination of factors including
lower gas demand in Asia due to the downturn and a recovery
in Japan’s nuclear power production, larger global supplies of
LNG, mild global temperatures and increased US production, gas
prices at the main worldwide markets fell by a far bigger amount
than crude oil prices. For example, the price of gas at the Italian
spot market against which the realized price of our equity gas
production in Europe is benchmarked, declined by 34% compared to
9% for the price of crude oil.
In 2019, the Company estimated that lower hydrocarbon prices
negatively affected the Exploration & Production operating profit
for approximately €2.23 billion, with the large majority of this loss
deriving from lower gas prices.
Lower oil and gas prices over prolonged periods of time or, in the
worst of the scenarios, a structural decline in oil and gas prices
may have material adverse effects on Eni’s performance and
business outlook, because such a scenario may limit the Group’s
funds available to finance expansion projects, further reducing the
Company’s ability to grow future production and revenues, and to
discharge contractual obligations. The Company may also need
to review investment decisions and the viability of development
projects and capex plans and, as a result of this review, the
Company could reschedule, postpone or curtail development
projects. A structural decline in hydrocarbon prices could trigger
a review of the carrying amounts of oil and gas properties and
this could result in recording material asset impairments and also
could result in the de-booking of proved reserves, if they become
uneconomic in this type of environment. Finally, in response to
weakened oil and gas industry conditions and resulting revisions
made to rating agency commodity price assumptions, lower
commodity prices may also reduce the Group’s access to capital
and lead to a downgrade or other negative rating action with
respect to the Group’s credit rating by rating agencies. These
downgrades may negatively affect the Group’s cost of capital,
increase the Group’s financial expenses, and may limit the Group’s
ability to access capital markets and execute aspects of the Group’s
business plans. All of these risks may adversely and materially
impact the Group’s results of operations, cash flow, liquidity,
business prospects, financial condition, and shareholder returns,
including dividends, the amount of funds available for stock
repurchases and the price of Eni’s share.
Eni estimates that approximately 50% of its current production
is exposed to fluctuations in hydrocarbons prices. Exposure to
this strategic risk is not subject to economic hedging, except for
some specific market conditions or transactions. The remaining
portion of Eni’s current production is largely unaffected by crude
oil price movements considering that the Company’s property
portfolio is characterised by a sizeable presence of production
sharing contracts, whereby the Company is entitled to a portion
of a field’s reserves, the sale of which is intended to cover
expenditures incurred by the Company to develop and operate
the field. The higher the reference prices for Brent crude oil used
to estimate Eni’s proved reserves, the lower the number of barrels
necessary to recover the same amount of expenditure and hence
production, and vice versa. If oil prices differ significantly from Eni’s
own forecasts, the result of the above mentioned sensitivity of
production to oil price changes may be significantly different.
Margins on the production and sale of fuels and other refined
products, chemical commodities, other energy commodities and
in the wholesale marketing of natural gas are driven by economic
growth, global and regional dynamics in supplies and demands
and other competitive factors. Generally speaking, the prices of
products mirror that of oil-based feedstock, but they can also
move independently. Margins for refined and chemical products
depend upon the speed at which products’ prices adjust to reflect
movements in oil prices. Margins at our business of wholesale
marketing of natural gas are driven by the spreads between spot
prices at continental hubs to which our procurement costs are
indexed and the spot prices at the Italian hub where a large part of
our gas sales occur. These spreads can be very volatile.
The COVID-19 impact and current trends in the oil market
The outbreak of a contagious disease known as COVID-19 which
has spread rapidly to many countries in the world at the beginning
of 2020 and is currently ongoing has triggered a sharp sell-off in
FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIESEni Annual Report 2019 90
energy commodities markets due to a sudden drop in worldwide
consumption of oil, gas and other energy products as a result
of measures taken worldwide to contain the spread of the
disease. In early March 2020, members of the OPEC+ failed to
reach an agreement for additional oil production cuts proposed
by some participants to counteract the COVID-19 effects. These
developments together triggered a collapse in crude oil prices. As
of the end of March 2020, the price of the Brent crude benchmark
has fallen by more than 50% from the value recorded before the
onset of the disease at more than 65 $/bbl in early January 2020;
the average Brent price for the first quarter 2020 of approximately
51 $/bbl has fallen by a considerably lower amount over the
corresponding period a year ago (down by approximately 20%).
Also, the price of natural gas at the Italian spot market “PSV”,
which is the main benchmark for sales volumes of equity gas
production has fallen in this period, with the average price for
the first quarter 2020 at approximately 3.7 $/mmBTU, down by
approximately 50% over the year-ago quarter.
Should these developments prolong beyond the short term, they
could represent a material risk to the outlook of Oil & Gas companies
considering the already weak fundamentals of the sector due to
continued oversupply and changing consumers’ attitudes toward
hydrocarbons due to rising climate-related issues.
Management has estimated the Company’s operating cash flows to
vary by approximately €150 million for each one-dollar change in the
price of the Brent crude oil benchmark with respect to the price case
assumed in Eni’s financial projections for 2020; regarding the price
of natural gas at the PSV, it has been estimated a variation of +/-€235
million in the operating cash flow for a +/-1 $/mmBTU change in the
price of the PSV compared to our financial assumptions.
Future trends in crude oil and natural gas prices will greatly depend
on how the current COVID-19 crisis unfolds and on how long it lasts.
Under the worst of the assumptions, the spread of the disease
could trigger a global recession which could materially hit demand
for energy products and prices of energy commodities. This
scenario could be further complicated in case the OPEC+ agreement
effectively ceases supporting crude oil prices. These trends could
have a material and adverse effect on our results of operations,
cash flow, liquidity and business prospects, including trends in Eni
shares and shareholders’ returns. However, in recent years the
Company has taken several steps to improve its balance sheet
and the resilience of the business to the volatility of hydrocarbons
prices. Due to continued exploration success at competitive
discovery costs, the deployment of an efficient model to develop
hydrocarbons reserves based on a phased approach, reduction
of time-to-market and design-to-cost, as well as continued
control of operating expenses, we believe that our portfolio of Oil
& Gas projects can withstand a significant oil price downturn,
leveraging on low break-even prices. We retains some levers of
financial flexibility in case of a significant contraction in cash flow
from operations. The Group has established a liquidity reserve
consisting of very liquid sovereign bonds and corporate securities
which amounted to €6.8 billion at the balance sheet date and
are marked to market, which together with cash on hands
of approximately €6 billion will cushion the impact of a price
downturn, also of severe proportions. Furthermore, we have as of
December 31, 2019, undrawn uncommitted borrowing facilities
amounting to €13,299 million and undrawn long-term committed
borrowing facilities of €4,667 million. Those facilities bore interest
rates reflecting prevailing conditions on the marketplace. The
main financial commitment of 2020 include long-term debt
maturities of approximately €3.2 billion, short-term debt of €2.45
billion, while our take-or-pay obligations under long-term gas
contracts and other similar obligations amount to an estimated
€8 billion at our budget scenario.
We are continuing to evalute the effects of the recent trends
in the oil market. This assessment includes an update to the
oil price scenario and management actions to counteract the
changed environment, the effects of which are currently not
yet determinable and will be accounted for in future reporting
periods. To date, in response to the sharp decrease in commodities
prices and the foreseeable constraints arising from the COVID-19
pandemic, management has revised its capital plans and
updated the commodities scenario for the years 2020 and 2021.
Managment is now assuming for planning purposes a Brent price
of 40-45 $/bbl in 2020 and of 50-55 $/bbl for 2021. In 2020,
management is planning to reduce capital expenditures by around
€2 billion, equal to 25% of the amount originally planned and opex
by around €400 million. In 2021, Eni expects a capital expenditures
reduction of around €2.5-3 billion, equal to 30-35% of the capex
scheduled for the same year in the business plan.
The projects involved in this capex reduction are related mainly
to upstream activities, particularly production optimization and
new projects developments scheduled to start in the short term.
In both cases, activities will be restarted as soon as appropriate
market conditions return, and related production will be recovered
accordingly. As a result of these measures and the current
depressed scenario, production in 2020 is expected to be between
1.8 and 1.84 million barrels of oil equivalent per day, which would
remain unchanged in the following year. Finally, management has
resolved to suspend the share repurchase program. The program
will be reconsidered when the Brent price for the referenced year,
which is the benchmark for decisions relating to the buyback plan
activation, is at least equal to 60 $/barrel.
There is strong competition worldwide, both within the oil industry
and with other industries, to supply energy and petroleum products
to the industrial, commercial and residential energy markets
Eni faces strong competition in each of its business segments.
The current competitive environment in which Eni operates
is characterised by volatile prices and margins of energy
commodities, limited product differentiation and complex
relationships with state-owned companies and national agencies
of the Countries where hydrocarbons reserves are located to
obtain mineral rights. As commodity prices are beyond the
Company’s control, Eni’s ability to remain competitive and
profitable in this environment requires continuous focus on
technological innovation, the achievement of efficiencies in
operating costs, effective management of capital resources
and the ability to provide valuable services to energy buyers. It
also depends on Eni’s ability to gain access to new investment
opportunities, both in Europe and worldwide.
FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIES 91
- In the Exploration & Production segment, Eni is facing
competition from both international and state-owned oil
companies for obtaining exploration and development rights,
and developing and applying new technologies to maximise
hydrocarbon recovery. Because of its smaller size relative to
other international oil companies, Eni may face a competitive
disadvantage when bidding for large scale or capital intensive
projects and it may be exposed to the risk of obtaining lower cost
savings in a deflationary environment compared to its larger
competitors given its potentially smaller market power with
respect to suppliers. Due to those competitive pressures, Eni
may fail to obtain new exploration and development acreage, to
apply and develop new technologies and to control costs.
- In the Gas & Power segment, Eni is facing strong competition
in the European wholesale gas markets to sell gas to industrial
customers, the thermoelectric sector and retailer companies
from other gas wholesalers, upstream companies, traders and
other players both in the Italian market and in markets across
Europe. In recent years, competition has been fuelled by muted
demand growth, oversupplies and the development of very liquid
European spot markets where large volumes of gas are traded
daily. Players are competing mainly in terms of pricing and,
to a lesser extent, on the ability to offer additional services to
the buyers of the commodity, like volume flexibilities, different
pricing options, the possibility to change the delivery point
and other optionality. Eni’s Gas & Power segment also engages
in the supply of gas and electricity to customers in the retail
markets mainly in Italy, France and other Countries in Europe.
Customers include households, large residential accounts
(hospitals, schools, public administration buildings, offices)
and small and medium-sized businesses located in urban
areas. The retail market is characterised by strong competition
among local selling companies which mainly compete in term of
pricing and the ability to bundle valuable services to the supply
of the energy commodity. In this segment, competition has
intensified in recent years due to the progressive liberalisation
of the market and the option on part of residential customers
to switch smoothly from one supplier to another. Management
believes that competition in the European wholesale and retail
gas markets will continue to negatively affect the performance of
Eni’s Gas & Power segment in future reporting periods.
- Eni is facing strong competitive pressure in its business of
gas-fired electricity generation which is largely sold in wholesale
markets in Italy. Margins on the sale of electricity have declined
in recent years due to oversupplies, weak economic growth
and inter-fuel competition. Management believes that these
factors will continue to negatively affect crack-spread margins
on electricity at Italian wholesale markets and the profitability of
this business unit in the foreseeable future.
- In the Refining & Marketing segment, Eni is facing competition
both in refining business and in the retail marketing activity.
Refining business, in recent years has been negatively affected
by a number of structural headwinds due to muted trends in the
European demand for fuels and continued competitive pressure
from players in the Middle East, the United States and Far East
Asia. Those competitors can leverage on larger plant scale and
cost economies, availability of cheaper feedstock and lower
energy expenses. Eni believes that the competitive environment
of the refining sector will remain challenging in the foreseeable
future, also considering refining overcapacity in the European
area and expectations of a new investment cycle driven by
capacity expansion plans announced in Asia and the Middle East,
potentially leading to a situation of global oversupplies of refinery
products. Furthermore, Eni’s refining margins are exposed to
the volatility in the spreads between crudes with high sulphur
content or sour crudes and the Brent crude benchmark, which
is a low-content sulphur crude. Eni complex refineries are able
to process sour crudes which typically trade at a discount over
the Brent crude. Historically, this discount has supported the
profitability of complex refineries, like our plant at Sannazzaro
in Italy. However, in the course of 2019, a shortfall in supplies of
sour crudes due to the production cuts implemented by OPEC,
lower exports from Venezuela and the United States’ sanctions
against Iran, drove an appreciation of the relative prices of sour
crudes as compared to the Brent, which negatively affected the
results of our refining business by reducing the advantage of
processing sour crudes. This development triggered a revision
of the profitability outlook of our complex plants, resulting in the
recording of an impairment loss of approximately €684 million
at our high-conversion Sannazzaro refinery. Our business of
marketing refined products to our service stations network
and to large accounts customer (aviation airlines, public
administrations, transport and industrial customers, bulk buyers
and resellers) is facing competition from other oil companies and
newcomers such as low-scale and local operators, un-branded
networks with light cost structure. All these operators compete
with each other primarily in terms of pricing and, to a lesser
extent, service quality.
In the Chemical business, Eni is facing strong competition
from well-established international players and state-
owned petrochemical companies, particularly in the most
commoditised market segments such as the production of basic
petrochemical products (like ethylene and polyethylene), whose
demand is a function of macroeconomic growth. Many of these
competitors based in the Far East and the Middle East are able
to benefit from cost economies due to larger plant scale, wide
geographic moat, availability of cheap feedstock and proximity
to end-markets. Excess worldwide capacity of petrochemical
commodities has also fuelled competition in this business.
Furthermore, petrochemical producers based in the United
States have regained market share, as their cost structure has
become competitive due to the availability of cheap feedstock
deriving from the production of domestic shale gas from which
ethane is derived, which is a cheaper raw material for the
production of ethylene than the oil-based feedstock utilised
by Eni’s petrochemical subsidiaries. Finally, rising public
concern about the climate change and the preservation of the
environment has begun to negatively affect the consumption of
single-use plastics. In 2019, the operating performance of the
Eni’s Chemical business was negative due lower demand from
end-user markets, particularly the automotive market, reflecting
a global economic slowdown and lower demand for single-use
plastics driven by stricter regulations and rising environmental
sensitivity. The effects of those trends were exacerbated by the
above mentioned competitive dynamics, resulting in a continued
pressure on petrochemical products margins. The Company
-
FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIESEni Annual Report 2019 92
does not expect any meaningful improvement in the trading
environment in the short to the medium-term due to competitive
headwinds described above and expectations for moderate
economic growth.
In case the Company is unable to effectively manage the above
described risks deriving from the competition in its business
segments, they may adversely impact the Group’s results of
operations, cash flow, liquidity, business prospects, financial
condition, and shareholder returns, including dividends, the
amount of funds available for stock repurchases and the price of
Eni’s share.
Safety, security, environmental and other operational risks
The Group engages in the exploration and production of oil and
natural gas, processing, transportation and refining of crude oil,
transport of natural gas, storage and distribution of petroleum
products and the production of base chemicals, plastics and
elastomers. By their nature, the Group’s operations expose Eni to a
wide range of significant health, safety, security and environmental
risks. Technical faults, malfunctioning of plants, equipment and
facilities, control systems failure, human errors, acts of sabotage,
attacks, loss of containment and adverse weather events can
trigger damaging consequences such as explosions, blow-outs,
fires, oil and gas spills from wells, pipeline and tankers, release
of contaminants and pollutants in the air, the ground and in the
water, toxic emissions and other negative events. The magnitude
of these risks is influenced by the geographic range, operational
diversity and technical complexity of Eni’s activities. Eni’s future
results of operations and liquidity depend on its ability to identify
and address the risks and hazards inherent to operating in those
industries.
In the Exploration & Production segment, Eni faces natural
hazards and other operational risks including those relating to
the physical and geological characteristics of oil and natural gas
fields. These include the risks of eruptions of crude oil or of natural
gas, discovery of hydrocarbon pockets with abnormal pressure,
crumbling of well openings, leaks that can harm the environment
and the security of Eni’s personnel and risks of blowout, fire or
explosion.
Eni’s activities in the Refining & Marketing and Chemicals segment
entail health, safety and environmental risks related to the
handling, transformation and distribution of oil, oil products and
certain petrochemical products. These risks can arise from the
intrinsic characteristics and the overall life cycle of the products
manufactured and the raw materials used in the manufacturing
process, such as oil-based feedstock, catalysts, additives and
monomer feedstock. These risks comprise flammability, toxicity,
long-term environmental impact such as greenhouse gas emissions
and risks of various forms of pollution and contamination of the
soil and the groundwater, emissions and discharges resulting from
their use and from recycling or disposing of materials and wastes
at the end of their useful life.
All of Eni’s segments of operations involve, to varying degrees, the
transportation of hydrocarbons. Risks in transportation activities
depend both on the hazardous nature of the products transported,
and on the transportation methods used (mainly pipelines,
shipping, river freight, rail, road and gas distribution networks), the
volumes involved and the sensitivity of the regions through which
the transport passes (quality of infrastructure, population density,
environmental considerations). All modes of transportation of
hydrocarbons are particularly susceptible to a loss of containment
of hydrocarbons and other hazardous materials, and, given the high
volumes involved, could present a significant risk to people, the
environment and the property.
Eni has material offshore operations relating to the exploration
and production of hydrocarbons. In 2019, approximately 60% of
Eni’s total oil and gas production for the year derived from offshore
fields, mainly in Egypt, Libya, Angola, Norway, Congo, Indonesia,
the United Arab Emirates, Italy, Ghana, Venezuela, the United
Kingdom, Nigeria and the United States. Offshore operations in the
oil and gas industry are inherently riskier than onshore activities.
Offshore accidents and spills could cause damage of catastrophic
proportions to the ecosystem and health and security of people
due to objective difficulties in handling hydrocarbons containment,
pollution, poisoning of water and organisms, length and complexity
of cleaning operations and other factors. Furthermore, offshore
operations are subject to marine risks, including storms and
other adverse weather conditions and vessel collisions, as well as
interruptions or termination by governmental authorities based on
safety, environmental and other considerations.
The Company has invested and will continue to invest significant
financial resources to continuously upgrade the methods and
systems for safeguarding the reliability of its plants, production
facilities, transport and storage infrastructures, the safety and the
health of its employees, contractors, local communities and the
environment; to prevent risks; to comply with applicable laws and
policies and to respond to and learn from unforeseen incidents. Eni
seeks to manage these operational risks by carefully designing
and building facilities, including wells, industrial complexes, plants
and equipment, pipelines, storage sites and other facilities, and
managing its operations in a safe and reliable manner and in
compliance with all applicable rules and regulations, as well as
with best available techniques. However, these measures may
not ultimately be completely successful in protecting against
those risks. Failure to manage these risks could cause unforeseen
incidents, including releases or oil spills, blowouts, fire, mechanical
failures and other incidents, all of which could lead to loss of life,
damage or destruction to properties, environmental damage, legal
liabilities and/or damage claims and consequently a disruption
in operations and potential economic losses that could have a
material and adverse effect on the Group’s results of operations,
cash flow, liquidity, business prospects, financial condition, and
shareholder returns, including dividends, the amount of funds
available for stock repurchases and the price of Eni’s share.
Eni’s operations are often conducted in difficult and/or
environmentally sensitive locations such as the Gulf of
Mexico, the Caspian Sea and the Arctic. In such locations, the
consequences of any incident could be greater than in other
FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIES 93
locations. Eni also faces risks once production is discontinued,
because Eni’s activities require the decommissioning of
productive infrastructures and environmental sites remediation
and clean-up. Furthermore, in certain situations where Eni is
not the operator, the Company may have limited influence and
control over third parties, which may limit its ability to manage
and control such risks. Eni retains worldwide third-party liability
insurance coverage, which is designed to hedge part of the
liabilities associated with damage to third parties, loss of value
to the Group’s assets related to unfavourable events and in
connection with environmental clean-up and remediation. As of
the date of this filing, maximum compensation allowed under
such insurance coverage is equal to $1.2 billion in case of
offshore incident and $1.4 billion in case of incident at onshore
facilities (refineries). Additionally, the Company may also
activate further insurance coverage in case of specific capital
projects and other industrial initiatives. Management believes
that its insurance coverage is in line with industry practice and
is sufficient to cover normal risks in its operations. However, the
Company is not insured against all potential risks. In the event of a
major environmental disaster, such as the incident which occurred
at the Macondo well in the Gulf of Mexico several years ago, for
example, Eni’s third-party liability insurance would not provide
any material coverage and thus the Company’s liability would far
exceed the maximum coverage provided by its insurance. The loss
Eni could suffer in the event of such a disaster would depend on
all the facts and circumstances of the event and would be subject
to a whole range of uncertainties, including legal uncertainty as
to the scope of liability for consequential damages, which may
include economic damage not directly connected to the disaster.
The Company cannot guarantee that it will not suffer any uninsured
loss and there can be no guarantee, particularly in the case of a
major environmental disaster or industrial accident, that such a
loss would not have a material adverse effect on the Company. The
occurrence of the above mentioned risks could have a material
and adverse impact on the Group’s results of operations, cash flow,
liquidity, business prospects, financial condition, and shareholder
returns, including dividends, the amount of funds available for
stock repurchases and the price of Eni’s share and could also
damage the Group’s reputation.
Rising public concern related to climate change has led and could
continue to lead to the adoption of national and international
laws and regulations which are expected to result in a decrease
of demand for hydrocarbons and increased compliance costs
for the Company. Eni is also exposed to risks of technological
breakthrough in the energy field and risks of unpredictable
extreme meteorological events linked to the climate change.
Growing worldwide public concern over greenhouse gas (GHG)
emissions and climate change, as well as increasingly stricter
regulations in this area, could adversely affect the Group’s
business. Those risks may emerge in the short and medium-
term, as well as over the long-term. The scientific community has
established a link between climate change, global warming and
increasing GHG concentration in the atmosphere. International
efforts to limit global warming have led, and Eni expects them to
continue to lead, to new laws and regulations designed to reduce
GHG emissions that are expected to bring about a gradual reduction
in the use of fossil fuels over the medium to long-term, notably
through the diversification of the energy mix. This trend could
accelerate as a number of governments throughout the world have
formally pledged to reach net-zero emissions by 2050 or earlier, like
in the case of EU, which may lead to a tightening of various measure
to constrain use of fossil fuels and this trend could increase both in
breadth and severity if more governments follow suit.
Governmental institutions have responded to the issue of climate
change on two fronts: on one side, governments can both impose
taxes on GHG emissions and incentivise a progressive shift in the
energy mix away from fossil fuels, for example, by subsidising the
power generation from renewable sources; on the other side they
can promote worldwide agreements to reduce the consumption of
hydrocarbons.
Some governments have already introduced carbon pricing
schemes, which can be an effective measure to reduce GHG
emissions at the lowest overall cost to society. Today, about half
of the direct GHG emissions coming from Eni operated assets are
included in national or supranational Carbon Pricing Mechanisms,
such as the European Emission Trading Scheme. Eni expects that
more governments will adopt similar schemes and that a growing
share of the Group’s GHG emissions will be subject to carbon-pricing
and other forms of climate regulation in the short to medium term.
Eni is already incurring operating costs related to its participation in
the European Emission Trading Scheme, whereby Eni is required to
purchase, on the open markets, emission allowances in case its GHG
emissions exceed freely-assigned emission allowances. In 2019 to
comply with this carbon emissions scheme, Eni purchased on the
open market allowances corresponding to 11.6 million tonnes of CO2
emissions for a cash cost of approximately €290 million. For 2020,
management expects to purchase allowances to cover approximately
16 million tonnes of CO2 due to stricter regulation on the allotment
of free allowances. Due to the likelihood of new regulations in this
area, Eni expects additional compliance obligations with respect
to the release, capture, and use of carbon dioxide that could result
in increased investments and higher project costs for Eni. Eni also
expects that governments will require companies to apply technical
measures to reduce their GHG emissions.
Eni expects that the achievement of the Paris Agreement goal
of holding the increase in global average temperature to less than
2 °C above pre-industrial levels, or the more stringent goal
advocated by the Intergovernmental Panel on Climate Change
(IPCC) to limit global warming to 1.5 °C, will strengthen the global
response to the threat of climate change and spur governments to
introduce further measures and policies targeting the reduction of
GHG emissions, which will likely reduce local demand for fossil fuels
in the long-term, thus negatively affecting global demand for oil
and natural gas. Eni’s business depends on the global demand for
oil and natural gas. If existing or future laws, regulations, treaties,
or international agreements related to GHG and climate change,
including incentives to conserve energy or use alternative energy
sources, technological breakthrough in the field of renewable
energies or mass-adoption of electric vehicles trigger a structural
FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIESEni Annual Report 2019 94
decline in the worldwide demand for oil and natural gas, our results
of operations and business prospects may be significantly and
adversely affected.
The scientific community has concluded that increasing global
average temperatures produces significant physical effects, such
as the increased frequency and severity of hurricanes, storms,
droughts, floods or other extreme climatic events that could
interfere with Eni’s operations and damage Eni’s facilities. Extreme
and unpredictable weather phenomena can result in material
disruption to Eni’s operations, and consequent loss of or damage
to properties and facilities, as well as a loss of output, loss of
revenues, increasing maintenance and repair expenses and cash
flow shortfall.
Finally, there is a reputational risk linked to the fact that oil
companies are increasingly perceived by institutions and the
general public as entities primarily responsible of the global
warming due to GHG emissions across the hydrocarbons value-
chain, particularly related with the use of energy products. This
could possibly make Eni’s shares less attractive to investment
funds and individual investors who have been more and more
assessing the risk profile of companies against their carbon
footprint when making investment decisions. Furthermore, a
growing number of financing institutions, including insurance
companies, appear to be considering limiting their exposure to
fossil fuel projects, as witnessed by a pledge from the World Bank
to stop financing upstream oil and gas projects and a proposal from
the EU finance minister to reduce the financing granted to Oil & Gas
projects via the EIB. This trend could have a material adverse effect
on the price of our securities and our ability to access equity or
other capital markets.
Accordingly, our ability to use financing for future projects may be
adversely impacted. Further, in some countries, governments and
regulators have filed lawsuits seeking to hold fossil fuel companies,
including Eni, liable for costs associated with climate change.
Losing any of these lawsuits could have a material adverse effect
on our business prospects.
As a result of these trends, climate-related risks could have a
material an adverse effect the Group’s results of operations,
cash flow, liquidity, business prospects, financial condition, and
shareholder returns, including dividends, the amount of funds
available for stock repurchases and the price of Eni’s share.
Our portfolio of oil and gas properties features a large weight of
natural gas, the least GHG-emitting fossil energy source, which
represented approximately 49% of Eni’s production in 2019 on an
available-for-sale basis; as of December 31, 2019, gas reserves
represented approximately 50% of Eni’s total proved reserves of its
subsidiary undertakings and joint ventures. The other pillar of our
resilient portfolio of Oil & Gas properties is the high incidence of
conventional projects, developed through phases and with low
CO2 intensity. We estimate that Oil & Gas projects under execution,
which will drive the expected production increase in the next four-
year period and attract a large part of the projected development
expenditures in the same period, have a price breakeven of
around 23 $/barrel. We believe that those elements of our portfolio
will mitigate the risk of stranded reserves going forward due
to risks of lower hydrocarbons demand in response to stricter
global environmental constraints and regulations and increasing
public sensitivity to the issue of global warming. Eni’s portfolio
exposure to those risks is reviewed annually against changing GHG
regulatory regimes and physical conditions to identify emerging
risks. To test the resilience of new capital projects, Eni assesses
potential costs associated with GHG emissions when evaluating all
such projects. New projects’ internal rates of return are stress-
tested against two sets of assumptions: i) Eni’s management
estimation of a cost per ton of carbon dioxide (CO2 ), which is
applied to the total GHG emissions of each capital project, while
retaining the management scenario for hydrocarbons prices; and
ii) the hydrocarbon prices and cost of CO2 emissions adopted in
the International Energy Agency (IEA) Sustainable Development
Scenario “IEA SDS”. This stress test is performed on a regular basis,
to monitor the progress of each project. The review performed at
the end of 2019 indicated that the internal rates of return of Eni’s
ongoing projects in aggregate should not be substantially affected
by a carbon pricing mechanism, even assuming that carbon costs
are not recoverable in the cost oil and non- deductible from profit
before taxes. The project development process features a number
of checks that may require the development of detailed GHG and
energy management plans. The majority of the projects have GHG
intensity targets that allow them under current assumptions to
compete in a more CO2 regulated future. These processes can lead
to projects being stopped, designs being changed, and potential
GHG mitigation investments being identified, in preparation for
when the economic conditions imposed by new regulation would
make these investments commercially compelling.
Furthermore, management performed a review of the recoverability
of the book values of the Company’s Oil & Gas assets under the
assumptions set forth in the IEA SDS WEO 2019. This review covered
all of the Oil & Gas cash generating unit (CGUs) that are regularly
tested for impairment in accordance to IAS 36. The IEA SDS sets
out an energy pathway consistent with the goal of achieving
universal energy access by 2030 and of reducing energy-related
CO2 emissions and air pollution in line with the goals of the Paris
Agreement. To reach these targets, the IEA SDS forecast a peak in
global CO2 emissions by 2025, an average decline of 4% per year
after that peak and net zero emissions in 2070. Global energy
demand is forecast to decline at a small pace notwithstanding the
assumptions of continued economic growth and universal access
to energy by 2030. The IEA SDS forecasts demand for oil to peak
before 2025 and then to decline to 50 million barrels/d by 2050
(currently it runs at approximately 100 million barrels/d). Gas
demand is projected to remain stable around the current level of
4,000 billion cubic meters per year till 2040. The hydrocarbons
pricing assumptions of the IEA SDS scenario are slightly lower than
Eni’s pricing assumptions regarding crude oil (for example in 2040
the price of crude oil is projected to be 10% lower in the IEA SDS
scenario compared to Eni’s own assumptions), while gas prices in
the IEA SDS scenario are projected to be slightly higher than Eni’s
scenario. CO2 emissions costs under the IEA SDS assumptions will
show a strong uptrend consistent with the goal of encouraging the
adoption of low carbon technologies. Such CO2 emissions costs as
FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIES 95
estimated by the IEA SDS would reach up to 140 $ per ton in real
terms 2018 (referred to Advanced Economies), which is higher
than Eni’s CO2 pricing trends and assumptions for the medium-long
term. The sensitivity test performed at Eni’s Oil & Gas CGUs under
the IEA SDS assumptions indicated the resiliency of Eni’s asset
portfolio in terms of carrying amounts and fair value, determining
a reduction of 7% in the total fair value of all of Eni’s Oil & Gas CGUs
compared to the result of the impairment review performed by the
Company in the preparation of its 2019 financial statements. That
reduction falls to a 2% decline assuming the recoverability of CO2
costs in the cost oil or the deductibility from the taxable income.
Furthermore, management assessed the recoverability of the
expected costs associated with the Company’s plans to ramp up the
participation in projects for forestry conservation and protection
from degradation, which is one of the tools of the Company’s path to
decarbonization. Those projects which have been started in 2019
envisage the purchase of carbon credits certified in accordance to
generally accepted international standards.
Management projects to build in future years a portfolio of forestry
projects intended to allow the Company to offset the net residual
“Scope 1 and 2” carbon emissions of the E&P business calculated
on equity production for the achievement of the carbon neutrality of
the business from 2030 onwards. Those costs are considered part of
the operating expenses of the E&P business and their recoverability
has been evaluated in relation to the CGU E&P segment as a whole.
When including those costs extrapolated along the reserves residual
life in the determination of the value-in-use of the E&P segment,
a 2% reduction in the headroom (excess of fair value over carrying
amounts) of the entire business segment is observed compared to
the result of the impairment review performed by the Company in the
preparation of its 2019 financial statements.
Ultimately, under management’s assumptions for a long-term
Brent price at 70 $/bbl (real terms 2022), which has remained
unchanged for the last few years, and at a reference price for
the Italian spot gas benchmark of 7.8 $/ mmBTU, Eni’s Oil &
Gas properties have exhibited a substantial resilience of their
carrying amounts, as highlighted by the trend in the recognition
of impairment losses in the last three years. In 2017 we recorded
a net reversal of €158 million and in 2018 we recorded net
impairment losses of €726 million; in 2019 we booked charges
of €1.2 billion. Impairment losses in those three years have been
driven mainly by asset-specific issues, which were acquired
during a historic phase of suspected peak supply, and in relation
to certain complex operating environments. However, considered
the following trends of the sector: the increased volatility of crude
oil prices which have been increasingly exposed to macro and
global risks; the continued oversupply in the oil markets which has
determined a reset in hydrocarbons realized prices and cash flows
of oil companies; growing uncertainty about long-term evolution
of the global oil demand in light of the rising commitment on part
of the international community at fighting the climate change
and speeding up the pace of the energy transition, the increase
in energy alternatives to fossil fuels and changing consumers’
preferences, management has evaluated the recoverability of the
book values of Eni’s Oil & Gas properties at different stress-test
scenarios, including the risk of stranded assets. Particularly, under
the more conservative set of the assumptions which envisages a
flat long-term Brent price of 50 $/bbl and at a flat Italian gas price
of 5 $/ mmBTU, management is estimating that approximately 85%
of the Company’s proven and probable/possible reserves (risked at
70% and 30% respectively) will be produced within 2035 and 94%
of their net present value will be realized. The net present value
of those production volumes, valorized at the most conservative
of the scenarios evaluated, is substantially aligned with the book
values of the net fixed assets of Eni’s Oil & Gas properties, including
Eni’s share of the fixed assets of our joint ventures like Vår Energi
AS, and including in the calculation the expected cash outflows
committed to the Company’s forestry projects.
In October 2018 the Intergovernmental Panel on Climate Change
(IPCC) stated, in a new report, that in order to limit global warming
to 1.5 °C, the world economy would need to undertake a deeper and
complex transformation. We recognize that meeting this challenge
in the next decades requires an even more rapid escalation, both in
term of size and speed, of changes than were foreseen in the Paris
Agreement. Currently, this scenario has yet to be complemented by
a full set of pricing and other operating assumptions, which once
available from the IPCC or other sources will be analyzed by the
Company for the purpose of updating stresstesting models and
methodologies.
The exploration and production of oil and natural gas is a high-
risk business because it is subject to the mining risk, to natural
hazards and to other uncertainties, including those relating to
the physical characteristics of oil and gas fields. It is a capital-
intensive business with significant up-front cash-outs and
extended pay-back periods of investments. Finally, it is strictly
regulated and subject to conditions imposed by governments
throughout the world.
A description of the main risks facing the Company’s business in
the exploration and production of oil and gas is provided below.
Exploring for finding hydrocarbons reserves may be unsuccessful
Exploration drilling for oil and gas involves numerous risks
including the risk of dry holes or failure to find commercial
quantities of hydrocarbons. The costs of drilling and completing
wells have margins of uncertainty, and drilling operations may
be unsuccessful because of a large variety of factors, including
geological failure, unexpected drilling conditions, pressure or
heterogeneities in formations, equipment failures, well control
(blowouts) and other forms of accidents. A large part of the
Company exploratory drilling operations is located offshore,
including in deep and ultra-deep waters, in remote areas and in
environmentally-sensitive locations (such as the Barents Sea,
the Gulf of Mexico and the Caspian Sea). In these locations, the
Company generally experiences higher operational risks and
more challenging conditions and incurs higher exploration costs
than onshore. Furthermore, deep and ultra-deep water operations
require significant time before commercial production of discovered
reserves can commence, increasing both the operational and the
financial risks associated with these activities. Because Eni plans
to make significant investments in executing exploration projects,
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it is likely that the Company will incur significant amounts of dry
hole expenses in future years. Unsuccessful exploration activities
and failure to discover additional commercial reserves could reduce
future production of oil and natural gas, which is highly dependent
on the rate of success of exploration projects, and could have an
adverse impact on Eni’s future performance.
Development projects bear significant operational risks which may
adversely affect actual returns
Eni is executing or is planning to execute several development
projects to produce and market hydrocarbon reserves. Certain
projects target the development of reserves in high-risk areas,
particularly deep offshore and in remote and hostile environments
or in environmentally-sensitive locations. Eni’s future results of
operations and business prospects depend heavily on its ability
to implement, develop and operate major projects as planned. Key
factors that may affect the economics of these projects include:
- the outcome of negotiations with joint venture partners,
from governments, state agencies or national oil companies, signing
agreement with the first party regulating a project’s contractual
terms such as the production sharing, obtaining partners’ approval,
environmental permits and other conditions, signing long-term
gas contracts, carrying out the concept design and the front-end
engineering and building and commissioning the related plants and
facilities. All these activities normally can take years to perform. As
a consequence, rates of return for such projects are exposed to the
volatility of oil and gas prices and costs which may be substantially
different from those estimated when the investment decision was
made, thereby leading to lower return rates. Moreover, projects
executed with partners and joint venture partners reduce the ability
of the Company to manage risks and costs, and Eni could have
limited influence over and control of the operations and performance
of its partners. Furthermore, Eni may not have full operational control
of the joint ventures in which it participates and may have exposure
to counterparty credit risk and disruption of operations and strategic
objectives due to the nature of its relationships.
governments and state-owned companies, suppliers, customers
or others to define project terms and conditions, including, for
example, Eni’s ability to negotiate favourable long-term contracts
to market gas reserves;
- commercial arrangements for pipelines and related equipment to
Finally, if the Company is unable to develop and operate major
projects as planned, particularly if the Company fails to accomplish
budgeted costs and time schedules, it could incur significant
impairment losses of capitalised costs associated with reduced
future cash flows of those projects.
transport and market hydrocarbons;
- timely issuance of permits and licenses by government agencies;
- the ability to carry out the front-end engineering design in order
to prevent the occurrence of technical inconvenience during
the execution phase; timely manufacturing and delivery of
critical equipment by contractors, shortages in the availability
of such equipment or lack of shipping yards where complex
offshore units such as FPSO and platforms are built; delays in
achievement of critical phases and project milestones;
- risks associated with the use of new technologies and the
inability to develop advanced technologies to maximise the
recoverability rate of hydrocarbons or gain access to previously
inaccessible reservoirs;
- performance in project execution on the part of contractors
who are awarded project construction activities generally
based on the EPC (Engineering, Procurement and Construction)
contractual scheme;
- changes in operating conditions and cost overruns;
- the actual performance of the reservoir and natural field decline;
and
- the ability and time necessary to build suitable transport
infrastructures to export production to final markets.
The occurrence of any of such risks may negatively affect the time-
to-market of the reserves and cause cost overruns and delayed
pay-back period, therefore adversely affecting the economic
returns of Eni’s development projects and the achievement of
production growth targets.
Inability to replace oil and natural gas reserves could adversely
impact results of operations and financial condition
Unless the Company is able to replace produced oil and natural
gas, its reserves will decline. In addition to being a function of
production, revisions and new discoveries, the Company’s reserve
replacement is also affected by the entitlement mechanism in its
production sharing agreements (“PSAs”), whereby the Company is
entitled to a portion of a field’s reserves, the sale of which is intended
to cover expenditures incurred by the Company to develop and
operate the field. The higher the reference prices for Brent crude
oil used to estimate Eni’s proved reserves, the lower the number
of barrels necessary to recover the same amount of expenditure,
and vice versa. Based on the current portfolio of oil and gas assets,
Eni’s management estimates that production entitlements vary on
average by approximately 530 barrels/d for each $1 change in oil
prices based on current Eni’s assumptions for oil prices. In 2019,
production benefitted marginally of lower oil prices which translated
into higher entitlements. In case oil prices differ significantly from
Eni’s own forecasts, the result of the above mentioned sensitivity of
production to oil price changes may be significantly different.
Future oil and gas production is dependent on the Company’s
ability to access new reserves through new discoveries, application
of improved techniques, success in development activity,
negotiations with national oil companies and other entities owners
of known reserves and acquisitions.
Development projects are typically long lead time due to the
complexity of the activities and tasks that need to be performed
before a project final investment decision is made and commercial
production can be achieved. Those activities include the appraisal
of a discovery to evaluate the technical and economic feasibility of
the development project, obtaining the necessary authorizations
An inability to replace produced reserves by discovering,
acquiring and developing additional reserves could adversely
impact future production levels and growth prospects. If Eni
is unsuccessful in meeting its long-term targets of production
growth and reserve replacement, Eni’s future total proved
reserves and production will decline.
FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIES 97
Uncertainties in estimates of oil and natural gas reserves
The accuracy of proved reserve estimates and of projections of
future rates of production and timing of development expenditures
depends on a number of factors, assumptions and variables,
including:
- the quality of available geological, technical and economic data
and their interpretation and judgement;
- projections regarding future rates of production and costs and
timing of development expenditures;
- changes in the prevailing tax rules, other government regulations
and contractual conditions;
- results of drilling, testing and the actual production performance
of Eni’s reservoirs after the date of the estimates which may
drive substantial upward or downward revisions; and
- changes in oil and natural gas prices which could affect the
quantities of Eni’s proved reserves since the estimates of
reserves are based on prices and costs existing as of the
date when these estimates are made. Lower oil prices or the
projections of higher operating and development costs may
impair the ability of the Company to economically produce
reserves leading to downward reserve revisions.
Many of the factors, assumptions and variables involved in
estimating proved reserves are subject to change over time and
therefore affect the estimates of oil and natural gas reserves.
The prices used in calculating Eni’s estimated proved reserves are,
in accordance with the US Securities and Exchange Commission (the
“US SEC”) requirements, calculated by determining the unweighted
arithmetic average of the first-day-of-the-month commodity prices
for the preceding 12 months. For the 12-months ending at December
31, 2019, average prices were based on 63 $/barrel for the Brent
crude oil; it was 71 $/barrel in 2018. Also the reference price of
natural gas was lower than in 2018. Those reductions resulted in us
having to remove volumes of proved reserves because they have
become uneconomical at the prices of 2019. Furthermore, compared
to the 2019 reference price, Brent prices have declined materially in
the first quarter of 2020. If such prices do not increase significantly
in the coming months, Eni’s future calculations of estimated proved
reserves will be based on lower commodity prices which would likely
result in the Company having to remove non-economic reserves from
its proved reserves in future periods.
Accordingly, the estimated reserves reported as of the end of 2019
could be significantly different from the quantities of oil and natural
gas that will be ultimately recovered. Any downward revision in
Eni’s estimated quantities of proved reserves would indicate lower
future production volumes.
The development of the Group’s proved undeveloped reserves may
take longer and may require higher levels of capital expenditures
than it currently anticipates or the Group’s proved undeveloped
reserves may not ultimately be developed or produced
At December 31, 2019, approximately 29% of the Group’s total
estimated proved reserves (by volume) were undeveloped
and may not be ultimately developed or produced. Recovery of
undeveloped reserves requires significant capital expenditures
and successful drilling operations. The Group’s reserve estimates
assume it can and will make these expenditures and conduct these
operations successfully. These assumptions may not prove to be
accurate. The Group’s reserve report at December 31, 2019 includes
estimates of total future development and decommissioning
costs associated with the Group’s proved total reserves of
approximately €35.7 billion (undiscounted, including consolidated
subsidiaries and equity-accounted entities). It cannot be certain
that estimated costs of the development of these reserves will
prove correct, development will occur as scheduled, or the results
of such development will be as estimated. In case of change in
the Company’s plans to develop those reserves, or if it is not
otherwise able to successfully develop these reserves as a result
of the Group’s inability to fund necessary capital expenditures or
otherwise, it will be required to remove the associated volumes
from the Group’s reported proved reserves.
Oil and gas activity may be subject to increasingly high levels of
income taxes and royalties
Oil and gas operations are subject to the payment of royalties
and income taxes, which tend to be higher than those payable in
many other commercial activities. Furthermore, in recent years,
Eni has experienced adverse changes in the tax regimes applicable
to oil and gas operations in a number of Countries where the
Company conducts its upstream operations. As a result of these
trends, management estimates that the tax rate applicable to the
Company’s oil and gas operations is materially higher than the
Italian statutory tax rate for corporate profit, which currently stands
at 24%. In 2019 the effective tax rate was 97.3% due to a particularly
unfavourable oil and gas price scenario.
Management believes that the marginal tax rate in the oil and gas
industry tends to increase in correlation with higher oil prices,
which could make it more difficult for Eni to translate higher oil
prices into increased net profit. However, the Company does not
expect that the marginal tax rate will decrease in response to falling
oil prices.
In the current uncertain financial and economic environment,
governments are facing greater pressure on public finances, which
may induce them to intervene in the fiscal framework for the oil
and gas industry, including the risk of increased taxation, windfall
taxes, and even nationalisations and expropriations.
The present value of future net revenues from Eni’s proved reserves
will not necessarily be the same as the current market value of
Eni’s estimated crude oil and natural gas reserves
The present value of future net revenues from Eni’s proved reserves
may differ from the current market value of Eni’s estimated crude
oil and natural gas reserves. In accordance with the SEC rules, Eni
bases the estimated discounted future net revenues from proved
reserves on the 12-month un-weighted arithmetic average of the
first-day-of-the-month commodity prices for the preceding twelve
months. Actual future prices may be materially higher or lower than
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the SEC pricing used in the calculations. Actual future net revenues
from crude oil and natural gas properties will be affected by factors
such as:
- the actual prices Eni receives for sales of crude oil and natural gas;
- the actual cost and timing of development and production
expenditures;
- the timing and amount of actual production; and
- changes in governmental regulations or taxation.
The timing of both Eni’s production and its incurrence of expenses
in connection with the development and production of crude oil and
natural gas properties will affect the timing and amount of actual
future net revenues from proved reserves, and thus their actual
present value. Additionally, the 10% discount factor Eni uses when
calculating discounted future net revenues may not be the most
appropriate discount factor based on interest rates in effect from
time to time and risks associated with Eni’s reserves or the crude
oil and natural gas industry in general. At December 31, 2019, the
net present value of Eni’s proved reserves totalled approximately
€50.9 billion. The average prices used to estimate Eni’s proved
reserves and the net present value at December 31, 2019, as
calculated in accordance with the SEC rules, were 63 $/barrel for
the Brent crude oil. Actual future prices may materially differ from
those used in our year-end estimates. Commodity prices have
decreased materially in the first quarter of 2020 compared to the
price used in the reserve calculations at 2019 year-end. Holding all
other factors constant, if commodity prices used in Eni’s year-end
reserve estimates at end of 2020 were in line with the pricing
environment existing at the end of the first quarter of 2020, Eni’s
PV-10 at December 31, 2020 would likely decrease significantly.
Oil and gas activity may be subject to increasingly high levels of
regulations throughout the world, which may impact our extraction
activities and the recoverability of reserves
The production of oil and natural gas is highly regulated and is
subject to conditions imposed by governments throughout the
world in matters such as the award of exploration and production
leases, the imposition of specific drilling and other work obligations,
environmental protection measures, control over the development
and abandonment of fields and installations, and restrictions on
production. These risks can limit the Group access to hydrocarbons
reserves or may have the Group to redesign, curtail or cease its
Oil & Gas operation.
In Italy, the activities of hydrocarbon development and
production are performed by oil companies in accordance to
concessions granted by the Ministry of Economic Development
in agreement with the relevant Region territorially involved in
the case of onshore concessions. Concessions are granted for
an initial twenty-year term; the concessionaire is entitled to a
ten-year extension and then to one or more five-year extensions
to fully recover a field’s reserves on condition that he has
fulfilled all obligations related to the work program agreed in
the initial concession award. In case of delay in the award of an
extension, the original concession remains fully effective until
the administrative procedure to grant an extension is finalized.
These general rules are to be coordinated with a new law that
was enacted on February 12, 2019. This law requires certain
Italian administrative bodies to adopt within eighteen months
(i.e. by August 2020) a plan intended to identify areas that are
suitable for carrying out exploration, development and production
of hydrocarbons in the national territory, including the territorial
seawaters. Until approval of such a plan, it is established a
moratorium on exploration activities, including the award of
new exploration leases. Following the plan approval, exploration
permits resume their efficacy in areas that have been identified
as suitable and new exploration permits can be awarded; on the
contrary, in unsuitable areas, exploration permits are repealed,
applications for obtaining new exploration permits ongoing at
the time of the law enactment are rejected and no new permit
application can be filed. As far as development and production
concessions are concerned, pending the national plan approval,
ongoing concessions retain their efficacy and administrative
procedures underway to grant extension to expired concession
remain unaffected; instead no applications to obtain new
concession can be filed. Once the above mentioned national plan
is adopted, development and production concessions that fall in
suitable areas can be granted further extensions and applications
for new concessions can be filed; on the contrary development
and production concessions current at the approval of the
national plan that fall in unsuitable areas are repealed at their
expiration and no further extensions can be granted, nor new
concession applications can be filed or awarded. According to the
statute, areas that are suitable to the activities of exploring and
developing hydrocarbons must conform to a number of criteria
including morphological characteristics and social, urbanistic and
industrial constraints, with particular bias for the hydrogeological
balance, current territorial planning and with regard to marine
areas for externalities on the ecosystem, reviews of marine
routes, fishing and any possible impacts on the coastline.
The Group’s largest operated development concession in Italy is
Val d’Agri, which has expired on October 26, 2019. Development
activities at the concession have continued since then in
accordance to the “prorogation regime” described above, within the
limits of the work plan approved when the concession was firstly
granted. The Company filed an application to obtain a ten-year
extension of the concession in accordance to the terms set by
the law and before the enactment of the new law on the national
plan for hydrocarbons activity. In this application the Company
confirmed the same work program as in the original concession
award. Other 33 Italian concessions for hydrocarbons development
and production have expired, where the Company operations are
underway in accordance to the ongoing prorogation regime. The
Company has filed requests for extensions within the terms of the
law also for those concessions.
As far as proven reserves estimates are concerned, management
believes the criteria laid out in the new law to be high-level
principles, which make it difficult identifying in a reliable and
objective manner areas that might be suitable or unsuitable to
hydrocarbons activities before the plan is adopted by Italian
authorities. Therefore, management is not currently in the position
to make a reliable and fair estimation of future impacts of the
new law provisions on the recoverability of the volumes of proved
FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIES 99
reserves booked in Italy and the associated future cash flows.
However, based on the review of all facts and circumstances and on
the current knowledge of the matter, management does not expect
any material impact on the Group future performance.
Eni’s future performance depends on its ability to identify and
mitigate the above mentioned risks and hazards which are inherent
to its Oil & Gas business. Failure to properly manage those risks,
Company’s underperformance at exploration, development and
reserve replacement activities or the occurrence of unforeseen
regulatory risks may adversely and materially impact the Group’s
results of operations, cash flow, liquidity, business prospects,
financial condition, and shareholder returns, including dividends,
the amount of funds available for stock repurchases and the price
of Eni’s share.
Risks related to political considerations – we are exposed to a
range of political developments and consequent changes to the
operating and regulatory environment
As of December 31, 2019, approximately 81% of Eni’s proved
hydrocarbon reserves were located in non-OECD Countries,
mainly in Africa, Central-East Asia and central-southern America,
where the socio-political framework, the financial system and
the macroeconomic outlook are less stable than in the OECD
Countries. In those non-OECD Countries, Eni is exposed to a wide
range of political risks and uncertainties, which may impair Eni’s
ability to continue operating in an economically viable way, either
temporarily or permanently, and Eni’s ability to access oil and
gas reserves. Particularly, Eni faces risks in connection with the
following, possible issues:
- socio-political instability leading to internal conflicts, revolutions,
establishment of non-democratic regimes, protests, attacks,
strikes and other forms of civil disorder and unrest, such as
strikes, riots, sabotage, acts of violence and similar events. These
risks could result in disruptions to economic activity, loss of
output, plant closures and shutdowns, project delays, the loss of
assets and threat to the security of personnel. They may disrupt
financial and commercial markets, including the supply of and
pricing for oil and natural gas, and generate greater political
and economic instability in some of the geographical areas in
which Eni operates. Additionally, any possible reprisals because
of military or other action, such as acts of terrorism in Europe,
the United States or elsewhere, could have a material adverse
effect on the world economy and hence on the global demand for
hydrocarbons;
lack of well-established and reliable legal systems and
uncertainties surrounding the enforcement of contractual rights;
-
- unfavourable enforcement of laws, regulations and contractual
arrangements leading, for example, to expropriation,
nationalisation or forced divestiture of assets and unilateral
cancellation or modification of contractual terms;
- sovereign default or financial instability due to the fact that those
Countries rely heavily on petroleum revenues to sustain public
finance and petroleum revenues have dramatically contracted
in recent years. Financial difficulties at Country level often
translate into failure on part of state-owned companies and
agencies to fulfil their financial obligations towards Eni relating
to funding capital commitments in projects operated by Eni or to
timely paying supplies of equity oil and gas volumes;
- restrictions on exploration, production, imports and exports;
- tax or royalty increases (including retroactive claims);
- difficulties in finding qualified international or local suppliers in
critical operating environments; and
- complex processes of granting authorisations or licences
affecting time-to-market of certain development projects.
Areas where Eni operates and where the Company is particularly
exposed to political risk include, but are not limited to: Libya, Egypt,
Algeria, Nigeria, Angola, Kazakhstan, Venezuela and Iraq.
In recent years, Eni’s operations in Libya were materially affected
by the revolution of 2011 and a change of regime, which caused
a prolonged period of political and social instability, still ongoing.
In 2011 Eni’s operations in the Country experienced an almost
one-year long shutdown due to security issues amidst a civil war,
causing a material impact on the Group results of operation and
cash flow for the year. In subsequent years Eni has experienced
frequent disruptions at its operations albeit of a smaller scale
than in 2011 due to security threats to its installations and
personnel. From the second half of 2018 a resurgence of socio-
political instability and a lack of a well-established institutional
framework have triggered the resumption of the civil war and
armed clashes in the area of Tripoli since April 2019. The situation
has continued to escalate and international negotiations aimed
at establishing a ceasefire has proven elusive. The Company
repatriated its personnel and strengthened security measures at
its plants and facilities. Despite the complexity of the operating
context, the Company’s activities in 2019 progressed smoothly
and in accordance to management’s plans with achievement
of full production plateau at the main ongoing projects of Wafa
compression and Bahr Essalam ph. 2. Going forward, management
believes that Libya’s geopolitical situation will continue to represent
a source of risk and uncertainty to Eni’s operations in the Country.
At the beginning of 2020 oil export terminals in the Southern
part of Libya were blocked, forcing the Company to shut down
operations at one of its production facilities (the Elephant oilfield).
In 2019, Libya represented approximately 16% of the Group’s
total production; this percentage is forecasted to decrease in the
medium term in line with the expected implementation of the Group
strategy intended to diversify the Group geographical presence to
better balance the geopolitical risk of the portfolio. In the event of
major adverse events, such as the escalation of the internal conflict
into a full-blown civil war, attacks, sabotage, social unrest, clashes
and other forms of civil disorder, Eni could be forced to reduce or to
shut down completely its producing activities at its Libyan fields,
which would significantly hit results of operations and cash flow.
Venezuela is currently experiencing a situation of financial stress
amidst an economic downturn due to lack of resources to support
the development of the Country’s hydrocarbons reserves, which
have negatively affected the Country production levels and hence
petroleum revenues. The situation has been made worse by certain
international sanctions targeting the Country’s financial system
and its ability to export crude oil to the United States’ market, which
is the main outlet of Venezuelan production (see also − “Sanctions
targets” below).
FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIESEni Annual Report 2019 100
Due to a deteriorated operating environment, the Group was
forced to de-book its proved undeveloped reserves at its two
major petroleum projects in the Country in recent years: the
50%-participated Cardón IV joint venture which is currently
operating a natural gas project and is supplying the product to the
national oil company, PDVSA, and the PetroJunín oilfield project in
joint venture with PDVSA. This latter project was almost entirely
written off in 2018. Also the Group has incurred credit losses due to
the continued difficulties on part of PDVSA to pay the receivables
for the gas supplies of Cardón IV, resulting in a significant amount of
overdue receivables. The joint-venture is systematically accounting
a loss provision on the revenues accrued. The credit expected loss
was based on management’s appreciation of the counterparty
risk driven by the findings of a review of the past experience of
sovereign defaults on which basis a deferral in the collection of
the gas revenues has been estimated. In the course of 2019 the
situation has stabilized, since the Group was able to collect a
percentage of gas receipts which was in line with management’s
estimates made in 2018 of the expected credit losses and no
further credit allowances were recorded. As of December 31,
2019, Eni’s invested capital in Venezuela was approximately $1.3
billion. Eni expects the financial and political outlook of Venezuela
to remain a risk factor to its operations in the Country for the
foreseeable future.
Nigeria is also undergoing a situation of financial stress, which
has translated into continuing delays in collecting overdue trade
receivables and credits for the carry of the expenditures of the
Nigerian joint operators at projects operated by Eni, resulting in the
incurrence of credit losses. Further, Eni’s activities in Nigeria have
been impacted in recent years by continuing incidences of theft, acts
of sabotage and other similar disruptions, which have jeopardised the
Company’s ability to conduct operations in full security, particularly
in the onshore area of the Niger Delta. Eni expects that those risks will
continue to affect Eni’s operations in Nigeria.
Management expects Eni’s credit exposure to Egypt to continue
increasing in the foreseeable future due to the planned production
ramp-up at the Zohr offshore gas field and to development of existing
gas reserves at other projects. Because the whole of the Group’s gas
production is sold to local state-owned companies, Eni expects a
significant increase in the credit risk exposure to Egypt, where we
experienced some issues at collecting overdue trade receivables
during the oil downturn. Eni will continue to monitor the counterparty
risk in future years considering the significant volumes of gas
expected to be supplied to Egypt’s national oil companies.
In addition to the above risks, the United Kingdom left the European
Union (EU) at the end of January 2020. As a result of this decision,
it is possible that we may experience delays in moving our products
and employees between the UK and EU. Also, additional tariffs and
taxes could impact the demand for some of our products and this,
combined with the potential adverse changes in macroeconomic
conditions in both the EU and UK, could have a material adverse
effect on the energy demand.
Eni is closely monitoring political, social and economic risks of the
Countries in which it has invested or intends to invest, in order to
evaluate the economic and financial return of capital projects and
to selectively evaluate projects. While the occurrence of these
events is unpredictable, the occurrence of any such risks may
adversely and materially impact the Group’s results of operations,
cash flow, liquidity, business prospects, financial condition, and
shareholder returns, including dividends, the amount of funds
available for stock repurchases and the price of Eni’s share.
Sanction targets
In response to the Russia-Ukraine crisis, the European Union and
the United States have enacted sanctions targeting, inter alia, the
financial and energy sectors in Russia by restricting the supply
of certain oil and gas items and services to Russia and certain
forms of financing. Eni has adapted its activities to the applicable
sanctions and will adapt its business to any further restrictive
measures that could be adopted by the relevant authorities.
In 2017, the United States’ government tightened the sanction
regime against Russia by enacting the “Countering America’s
Adversaries Through Sanctions Act”. In response to these new
measures, the Company could possibly refrain from pursuing
business opportunities in Russia, while currently the Company
is not engaged in any upstream projects in Russia. It is possible
that wider sanctions targeting the Russian energy, banking and/
or finance industries may be implemented. Further sanctions
imposed on Russia, Russian citizens or Russian companies by
the international community, such as restrictions on purchases
of Russian gas by European companies or measures restricting
dealings with Russian counterparties, could adversely impact
Eni’s business, results of operations and cash flow. Furthermore,
an escalation of the international crisis, resulting in a tightening
of sanctions, could entail a significant disruption of energy supply
and trade flows globally, which could have a material adverse
effect on the Group’s business, financial conditions, results of
operations and prospects. In 2017, the United States administration
enacted certain financing sanctions against Venezuela, which
prohibit any United States person to be involved in all transactions
related to, provision of financing for, and other dealings in, among
other things, any debt owed to the Government of Venezuela
that is pledged as collateral after the effective date, including
accounts receivable. Recently, the United States administration
has resolved to impose an embargo on the import of crude oil from
Venezuela state-owned oil company, PDVSA and has restricted
the ability of United States dealers to trade bonds issued by the
Government of Venezuela and its affiliates. Further increases of
the prohibitions against the Government of Venezuela (and the
entities owned or controlled by it) has been enacted during the
course of 2019, with inclusion of our Venezuelan partner, PDVSA,
in the “Specially Designated Nationals and Blocked Persons List
and the introduction of measures intended to freeze the assets of
the Venezuelan governments and of its affiliated persons. Even if
the current US sanctions are “primary” and therefore substantially
dedicated to US persons only, retaliatory measures and other
adverse consequences may interest also foreign entities which
operate with Venezuelan listed entities as it may occur in the
case of transactions which show a US nexus, which may trigger
the application of sanctions. Eni is carefully evaluating on a case
by case basis the adoption of measures adequate to minimize
FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIES
101
its exposure to any sanction risk which may affect its business
operation. In any case, the US sanction are expected to add further
stress to the already complex financial, political and operating
outlook of the Country, which could limit the ability of Eni to recover
its investments.
Risks in the Company’s Gas & Power business
Risks associated with the trading environment and competition in
the gas market
Our Gas & Power business comprises the results of the wholesale
gas business which has a portfolio of long-term gas supply
contracts and other related assets, the trading of LNG on a
global scale, the production and marketing of electricity and the
marketing of gas and power in the retail sector.
The results of our wholesale gas business are subject to global and
regional dynamics of gas demand and supplies and to trends in the
spreads between the procurement costs of gas, which are linked
to spot prices at European hubs or to the price of crude oil, and the
selling prices of gas which are mainly indexed to spot prices at the
Italian hub. Those spreads can be very volatile. The results of the
LNG business are mainly influenced by the global balance between
demand and supplies.
Worldwide gas prices have been on a downward path since the
second half of 2018 and this trend has deteriorated further
throughout the course of 2019. This was driven by a global economic
slowdown, which hit severely Asian large gas-consuming Countries,
like China, South Korea and Japan, also due to a recovery in
nuclear production, a build-up in gas supplies due to the entry into
service of new Liquefied Natural Gas (“LNG”) projects and rising US
production, competition from renewables, mild global temperatures
and inventory levels above historic averages. The fall of gas prices
at our main European outlet markets was broadly in line with other
geographies due to above mentioned dynamics and the growing role
of LNG supplies which have enhanced the interconnection among
regional markets and markets liquidity. In fact, during the course of
2019 a reduction in LNG imports from Asian markets forced operators
to re-direct LNG supplies to Europe, thus making for any slowdown
in the Continent’s internal production and pressuring gas prices
which have levelled across the various geographies. These trends
negatively affected the results of our LNG business due to lower
traded volumes and margins. The trading environment for LNG has
deteriorated further in the first months of 2020 due on ongoing global
deceleration in energy demand.
Management believes that gas prices in Europe will remain weak
due to the forecast of sluggish economic growth, a muted demand
outlook and global oversupplies of gas. Furthermore, several final
investment decisions have been made in 2019 relating to large LNG
projects with an estimated capacity of 60 million tonnes per year,
which are due to come on stream within five-six years adding to
already oversupplied markets.
Against the backdrop of a difficult competitive environment, Eni
anticipates a number of risk factors to the profitability outlook of
the Company’s gas marketing business over the four-year planning
period, considering the Company’s operational constraints dictated
by its long-term gas supply contracts with take-or-pay clauses,
which expose Eni to a volume risk, as the Company is contractually
required to purchase minimum annual amounts of gas or, in case of
failure, to pay the corresponding price. Additionally, Eni has booked
the transportation rights along the main gas backbones across
Europe to deliver its contracted gas volumes to end-markets. Risks
to the Gas & Power business include continuing oversupplies,
pricing pressures, volatile margins and the risk of deteriorating
spreads of Italian spot prices versus continental benchmarks. A
reduction of the spreads between Italian and European spot prices
for gas could negatively affect the profitability of our business by
reducing the total addressable market and by reducing the margin
to cover the business’s sunk costs and other fixed expenses. Eni’s
management is planning to continue its strategy of renegotiating
the Company’s long-term gas supply contracts in order to
constantly align pricing terms to current market conditions as
they evolve and to obtain greater operational flexibility (volumes,
delivery points among others), considering the risk factors
described above. The revision clauses provided by these contracts
state the right of each counterparty to renegotiate the economic
terms and other contractual conditions periodically, in relation to
ongoing changes in the gas scenario. Management believes that the
outcome of those renegotiations is uncertain in respect of both the
amount of the economic benefits that will be ultimately obtained
and the timing of recognition of profit. Furthermore, in case Eni
and the gas suppliers fail to agree on revised contractual terms,
both parties can start an arbitration procedure to obtain revised
contractual conditions. All these possible developments within
the renegotiation process could increase the level of risks and
uncertainties relating the outcome of those renegotiations.
Trends in the LNG business are expected to remain weak in 2020
due to a global glut of LNG.
Current, negative trends in gas demands and supplies may impair
the Company’s ability to fulfil its minimum off-take obligations in
connection with its take-or-pay, long-term gas supply contracts
Eni long-term gas supply contracts with national operators
of certain key producing Countries, from where most of the
European gas supplies are sourced (Russia, Algeria, Libya,
the Netherlands and Norway), include take-or-pay clauses
whereby the Company has an obligation to lift minimum, pre-set
volumes of gas in each year of the contractual term or, in case
of failure, to pay the whole price, or a fraction of that price, up
to the minimum contractual quantity. Similar considerations
apply to ship-or-pay contractual obligations. Long-term gas
supply contracts with take-or pay clauses expose the Company
to a volume risk, as the Company is obligated to purchase an
annual minimum volume of gas, or in case of failure, to pay the
underlying price. Management believes that the current level of
market liquidity, the outlook of the European gas sector which is
featuring muted demand growth, strong competitive pressures
and large supplies, as well as any possible change in sector-
specific regulation represent risk factors to the Company’s
ongoing ability to fulfil its minimum take obligations associated
with its long-term supply contracts.
FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIESEni Annual Report 2019 102
Risks associated with the regulatory powers entrusted to
the Italian Regulatory Authority for Energy, Networks and
Environment in the matter of pricing to residential customers
Eni’s Gas & Power segment is subject to regulatory risks mainly
in its domestic market in Italy. The Italian Regulatory Authority
for Energy, Networks and Environment (the “Authority”) is
entrusted with certain powers in the matter of natural gas pricing.
Specifically, the Authority retains a surveillance power on pricing
in the natural gas market in Italy and the power to establish
selling tariffs for the supply of natural gas to residential and
commercial users until the market is fully opened. Developments
in the regulatory framework intended to increase the level
of market liquidity or of de-regulation, or intended to reduce
operators’ ability to transfer to customers cost increases in raw
materials may negatively affect future sales margins of gas and
electricity, operating results and cash flow.
Risks related to environmental, health and safety regulations and
legal risks
Eni has incurred in the past, and will continue incurring, material
operating expenses and expenditures, and is exposed to business
risk in relation to compliance with applicable environmental, health
and safety regulations in future years, including compliance with
any national or international regulation on GHG emissions
Eni is subject to numerous European Union, international,
national, regional and local laws and regulations regarding the
impact of its operations on the environment and on health and
safety of employees, contractors, communities and on the value
of properties. Generally, these laws and regulations require
acquisition of a permit before drilling for hydrocarbons may
commence, restrict the types, quantities and concentration of
various substances that can be released into the environment
in connection with exploration, drilling and production activities,
including refinery and petrochemical plant operations, limit
or prohibit drilling activities in certain protected areas,
require to remove and dismantle drilling platforms and other
equipment and well plug-in once oil and gas operations have
terminated, provide for measures to be taken to protect the
safety of the workplace and the of plants and infrastructures,
and health of employees, contractors and other Company’s
collaborators and of communities involved by the Company’s
activities, and impose criminal or civil liabilities for polluting
the environment or harming employees’ or communities’ health
and safety resulting from the Group’s operations. These laws
and regulations control the emission of scrap substances and
pollutants, discipline the handling of hazardous materials and
set limits to the discharge in the environment of soil, water
or ground water contaminants, polluting air emissions and
noxious gases resulting from the operation of oil and natural
gas extraction and processing plants, petrochemical plants,
refineries, service stations, vessels, oil carriers, pipeline
systems and other facilities owned or operated by Eni. In
addition, Eni’s operations are subject to laws and regulations
relating to the production, handling, transportation, storage,
disposal and treatment of waste. Breaches of environmental,
health and safety laws and regulations as in the case of
negligent or willful release of pollutants and contaminants into
the atmosphere, the soil, water or groundwater or the overcome
of concentration threshold of contaminants set by the law
expose the Company to the incurrence of liabilities associated
with compensation for environmental, health or safety damage
and expenses for environmental remediation and clean-up.
Furthermore, in the case of violation of certain rules regarding
the safeguard of the environment and the health of employees,
contractors and other collaborators of the Company, and of
communities, the Company may incur liabilities in connection
with the negligent or willful violation of laws by its employees as
per Italian Law Decree No. 231/2001.
Environmental, health and safety laws and regulations have a
substantial impact on Eni’s operations. Management expects that
the Group will continue to incur significant amounts of operating
expenses and expenditures in the foreseeable future to comply
with laws and regulations and to safeguard the environment and
the health and safety of employees, contractors and communities
involved by the Company operations, including:
- costs to prevent, control, eliminate or reduce certain types of
air and water emissions and handle waste and other hazardous
materials, including the costs incurred in connection with
government action to address climate change (see the specific
section below on climate-related risks);
- remedial and clean-up measures related to environmental
contamination or accidents at various sites, including those
owned by third parties (see discussion below);
- damage compensation claimed by individuals and entities,
including local, regional or state administrations, should Eni
cause any kind of accident, oil spill, well blowouts, pollution,
contamination, emission of GHG and other air pollutants above
permitted levels or of any other hazardous gases, water, ground
or air contaminants or pollutants, as a result of its operations or if
the Company is found guilty of violating environmental laws and
regulations; and
- costs in connection with the decommissioning and removal of
drilling platforms and other facilities, and well plugging at the end
of Oil & Gas field production.
As a further result of any new laws and regulations or other
factors, like the actual or alleged occurrence of environmental
damage at Eni’s plants and facilities, the Company may be forced
to curtail, modify or cease certain operations or implement
temporary shutdowns of facilities. For example, in Italy we have
experienced in recent years a number of plant shutdowns at
our Val d’Agri profit centre due to environmental issues and oil
spill overs, causing loss of output and of revenues. The Italian
judicial authorities have started legal proceedings to verify
alleged environmental crimes or crimes against the public safety
and other criminal allegations as described in the notes to the
Consolidated Financial Statements.
If any of the risks set out above materialise, they could adversely
impact the Group’s results of operations, cash flow, liquidity,
business prospects, financial condition, and shareholder returns,
including dividends, the amount of funds available for stock
repurchases and the price of Eni’s share.
FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIES 103
Eni is exposed to the risk of material environmental liabilities in
addition to the provisions already accrued in the consolidated
financial statement.
Eni has incurred in the past and may incur in the future material
environmental liabilities in connection with the environmental
impact of its past and present industrial activities. Eni is also
exposed to claims under environmental requirements and, from
time to time, such claims have been made against us. Furthermore,
environmental regulations in Italy and elsewhere typically impose
strict liability. Strict liability means that in some situations Eni
could be exposed to liability for clean-up and remediation costs,
environmental damage, and other damages as a result of Eni’s
conduct of operations that was lawful at the time it occurred
or of the conduct of prior operators or other third parties. In
addition, plaintiffs may seek to obtain compensation for damage
resulting from events of contamination and pollution or in case
the Company is found liable of violations of any environmental
laws or regulations. In Italy, Eni is exposed to the risk of expenses
and environmental liabilities in connection with the impact of
its past activities at certain industrial hubs where the Group’s
products were produced, processed, stored, distributed or sold,
such as chemical plants, mineral-metallurgic plants, refineries
and other facilities, which were subsequently disposed of,
liquidated, closed or shut down. At these industrial hubs, Eni has
undertaken a number of initiatives to remediate and to clean-up
proprietary or concession areas that were allegedly contaminated
and polluted by the Group’s industrial activities. State or local
public administrations have sued Eni for environmental and
other damages and for clean-up and remediation measures in
addition to those which were performed by the Company, or which
the Company has committed to perform. In some cases, Eni
has been sued for alleged breach of criminal laws (for example
for alleged environmental crimes such as failure to perform
soil or groundwater reclamation, environmental disaster and
contamination, discharge of toxic materials, amongst others).
Although Eni believes that it may not be held liable for having
exceeded in the past pollution thresholds that are unlawful
according to current regulations but were allowed by laws then
effective, nor because the Group took over operations from third
parties, it cannot be excluded that Eni could potentially incur
such environmental liabilities. Eni’s financial statements account
for provisions relating to the costs to be incurred with respect to
clean-ups and remediation of contaminated areas and groundwater
for which a legal or constructive obligation exists and the
associated costs can be reasonably estimated in a reliable manner,
regardless of any previous liability attributable to other parties.
The accrued amounts represent management’s best estimates
of the Company’s existing liabilities. Management believes that it
is possible that in the future Eni may incur significant or material
environmental expenses and liabilities in addition to the amounts
already accrued due to: (i) the likelihood of as yet unknown
contamination; (ii) the results of ongoing surveys or surveys to be
carried out on the environmental status of certain Eni’s industrial
sites as required by the applicable regulations on contaminated
sites; (iii) unfavourable developments in ongoing litigation on the
environmental status of certain of the Company’s sites where a
number of public administrations and the Italian Ministry of the
Environment act as plaintiffs; (iv) the possibility that new litigation
might arise; (v) the probability that new and stricter environmental
laws might be implemented; and (vi) the circumstance that the
extent and cost of environmental restoration and remediation
programs are often inherently difficult to estimate leading to
underestimation of the future costs of remediation and restoration,
as well as unforeseen adverse developments both in the final
remediation costs and with respect to the final liability allocation
among the various parties involved at the sites. As a result of
these risks, environmental liabilities could be substantial and could
have a material adverse effect the Group’s results of operations,
cash flow, liquidity, business prospects, financial condition, and
shareholder returns, including dividends, the amount of funds
available for stock repurchases and the price of Eni’s share.
Risks related to legal proceedings and compliance with anti-
corruption legislation
Eni is the defendant in a number of civil and criminal actions
and administrative proceedings. In future years Eni may incur
significant losses in addition to the amounts already accrued in
connection with pending legal proceedings due to: (i) uncertainty
regarding the final outcome of each proceeding; (ii) the occurrence
of new developments that management could not take into
consideration when evaluating the likely outcome of each
proceeding in order to accrue the risk provisions as of the date
of the latest financial statements or to judge a negative outcome
only as possible or to conclude that a contingency loss could not
be estimate reliably; (iii) the emergence of new evidence and
information; and (iv) underestimation of probable future losses
due to the circumstance that they are often inherently difficult to
estimate. Certain legal proceedings and investigations in which
Eni or its subsidiaries or its officers and employees are defendant
involve the alleged breach of anti-bribery and anti-corruption laws
and regulations and other ethical misconduct. Such proceedings
are described in Note 27 to the Eni’s 2019 Annual Report on Form
20-F, under the heading “Legal Proceedings”. Ethical misconduct
and noncompliance with applicable laws and regulations, including
noncompliance with anti-bribery and anti-corruption laws, by Eni,
its officers and employees, its partners, agents or others that act on
the Group’s behalf, could expose Eni and its employees to criminal
and civil penalties and could be damaging to Eni’s reputation and
shareholder value.
Risks from acquisitions
Eni is constantly monitoring the oil and gas market in search of
opportunities to acquire individual assets or companies with a view
of achieving its growth targets or complementing its asset portfolio.
Acquisitions entail an execution risk – the risk that the acquirer
will not be able to effectively integrate the purchased assets
so as to achieve expected synergies. In addition, acquisitions
entail a financial risk – the risk of not being able to recover the
purchase costs of acquired assets, in case a prolonged decline in
the market prices of oil and natural gas occurs. Eni may also incur
unanticipated costs or assume unexpected liabilities and losses in
connection with companies or assets it acquires. If the integration
and financial risks related to acquisitions materialise, expected
synergies from acquisition may fall short of management’s targets
and Eni’s financial performance and shareholders’ returns may be
adversely affected.
FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIESEni Annual Report 2019 104
Risks deriving from Eni’s exposure to weather conditions
Significant changes in weather conditions in Italy and in the rest of
Europe from year to year may affect demand for natural gas and
some refined products. In colder years, demand for such products
is higher. Accordingly, the results of operations of the Gas & Power
segment and, to a lesser extent, the Refining & Marketing business,
as well as the comparability of results over different periods may
be affected by such changes in weather conditions. Over recent
years, this pattern could have been possibly affected by the rising
frequency of weather trends like milder winter or extreme weather
events like heatwaves or unusually cold snaps, which are possible
consequences of climate change.
Eni’s crisis management systems may be ineffective
Eni has developed contingency plans to continue or recover
operations following a disruption or incident. An inability to
restore or replace critical capacity to an agreed level within an
agreed period could prolong the impact of any disruption and
could severely affect business, operations and financial results.
Eni has crisis management plans and the capability to deal
with emergencies at every level of its operations. If Eni does not
respond or is not seen to respond in an appropriate manner to
either an external or internal crisis, this could adversely impact
the Group’s results of operations, cash flow, liquidity, business
prospects, financial condition, and shareholder returns, including
dividends, the amount of funds available for stock repurchases
and the price of Eni’s share.
Disruption to or breaches of Eni’s critical IT services or digital
infrastructure and security systems could adversely affect the
Group’s business, increase costs and damage our reputation
The Group’s activities depend heavily on the reliability and
security of its information technology (IT) systems and digital
security. The Group’s IT systems, some of which are managed by
third parties, are susceptible to being compromised, damaged,
disrupted or shutdown due to failures during the process of
upgrading or replacing software, databases or components, power
or network outages, hardware failures, cyber-attacks (viruses,
computer intrusions), user errors or natural disasters. The cyber
threat is constantly evolving. The oil and gas industry is subject
to fast-evolving risks from cyber threat actors, including nation
states, criminals, terrorists, hacktivists and insiders. Attacks are
becoming more sophisticated with regularly renewed techniques
while the digital transformation amplifies exposure to these cyber
threats. The adoption of new technologies, such as the Internet of
Things (IoT) or the migration to the cloud, as well as the evolution
of architectures for increasingly interconnected systems, are all
areas where cyber security is a very important issue. The Group
and its service providers may not be able to prevent third parties
from breaking into the Group’s IT systems, disrupting business
operations or communications infrastructure through denial-of-
service attacks, or gaining access to confidential or sensitive
information held in the system. The Group, like many companies,
has been and expects to continue to be the target of attempted
cybersecurity attacks. While the Group has not experienced
any such attack that has had a material impact on its business,
the Group cannot guarantee that its security measures will be
sufficient to prevent a material disruption, breach or compromise
in the future. As a result, the Group’s activities and assets could
sustain serious damage, services to clients could be interrupted,
material intellectual property could be divulged and, in some
cases, personal injury, property damage, environmental harm and
regulatory violations could occur.
If any of the risks set out above materialise, they could adversely
impact the Group’s results of operations, cash flow, liquidity,
business prospects, financial condition, and shareholder returns,
including dividends, the amount of funds available for stock
repurchases and the price of Eni’s share.
Violations of data protection laws carry fines and expose us and/
or our employees to criminal sanctions and civil suits.
Data protection laws and regulations apply to Eni and its joint
ventures and associates in the vast majority of Countries in
which we do business. The EU General Data Protection Regulation
(GDPR) came into effect in May 2018, which increased penalties
up to a maximum of 4% of global annual turnover for breach of the
regulation. The GDPR requires mandatory breach notification, the
standard for which is also followed outside the EU (particularly
in Asia). Non-compliance with data protection laws could expose
us to regulatory investigations, which could result in fines and
penalties as well as harm our reputation. In addition to imposing
fines, regulators may also issue orders to stop processing
personal data, which could disrupt operations. We could also
be subject to litigation from persons or corporations allegedly
affected by data protection violations. Violation of data protection
laws is a criminal offence in some Countries, and individuals can
be imprisoned or fined.
If any of the risks set out above materialise, they could adversely
impact the Group’s results of operations, cash flow, liquidity,
business prospects, financial condition, and shareholder returns,
including dividends, the amount of funds available for stock
repurchases and the price of Eni’s share.
FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIES Outlook
For further information on Eni’s business outlook and financial and operational targets, please see the chapter “Strategy”.
105
106
Consolidated disclosure
of non-financial information
in accordance with the Italian Legislative Decree 254/2016
Introduction
The Consolidated Disclosure of Non-Financial Information (NFI) is drafted
in accordance with the Italian Legislative Decree 254/2016 and the
“Sustainability Reporting Standards”, published by the Global Reporting
Initiative (GRI)1 and is structured on the three levers of Eni’s integrated
business model (Carbon Neutrality in the Long Term, Operational
Excellence Model, and Alliance for the promotion of Local Development)
whose objective is to create long-term value for stakeholders.
As in previous years, on the occasion of the Shareholders’ Meeting, Eni
will also publish Eni for, the voluntary sustainability report that aims to
further enhance non-financial disclosure. The 2019 edition of Eni for will
also include the annex “Carbon Neutrality in the Long Term”.
The NFI is included in the Management Report with the aim of making the
Annual Report the reference document to meet the information needs of
Eni’s stakeholders in a clear and concise manner, further favouring the
integrated disclosure of financial and non-financial information.
In order to avoid duplication and ensure that disclosures are as concise
as possible, the NFI provides an integrated view on the topics set out in
the Italian Legislative Decree 254/2016, also by providing references to
other sections of the Management Report or to the Corporate Governance
Report, if the information is already contained therein or to provide
further explanation. In particular, the Management Report illustrates:
- Eni’s business and governance model, at pages 4; 24-29;
- Risk management in the sections at pages 20-23: (i) “Integrated Risk
Management”, which describes Eni’s Integrated Risk Management
(IRM) model – including sustainability aspects –, the main activities
carried out in 2019 as well as Eni’s Top Risks and the main mitigation
actions; (ii) “Risk factors and uncertainties,” where the Groups main
risks, their potential impacts and treatment actions, in line with the
Italian legislation disclosure requirements, are described in greater
detail.
The NFI illustrates in detail:
- Company policies in the section “Main regulatory and guiding
instruments related to Legislative Decree 254/2016 topics”, which
describes the regulatory system composed of direction, coordination
and control instruments and others instruments which define the
operating procedures;
- Eni's "Organizational and Management Models” for the following
topics: environment, climate, people, health and safety, human
rights, suppliers, transparency and anti-corruption, local
communities, innovation and digitalization;
- the strategy on the above topics with the most significant initiatives
of the year and the main performance results with related
comments;
- risk management, linked to the areas covered by the Decree, which
are not dealt with in the Management Report, i.e., those risks that,
though mapped and monitored as part of Eni’s Integrated Risk
Management, are not considered top risks.
The contents of the “Carbon Neutrality in the Long Term” are drafted
according to the voluntary recommendations of the Task Force on
Climate-related Financial Disclosures (TCFD) set out by the Financial
Stability Board, of which Eni has been a member since its foundation,
in order to provide even clearer and more in-depth disclosure on
these issues.
Lastly, reference to the main United Nations Sustainable Development
Goals (SDGs) has been included in the various sections. These goals
are a valuable source of guidance for the international community and
for Eni in conducting its activities in Italy and abroad2.
Below is a table showing the correspondence between the information
content required by the Decree and its position within the NFI, the
Annual Report or the Corporate Governance Report.
AREAS OF THE ITALIAN
LEGISLATIVE DECREE
254/2016
COMPANY
MANAGEMENT MODEL
AND GOVERNANCE
Art. 3.1, paragraph a)
PARAGRAPHS INCLUDED
IN THE NFI
• Organizational and management models,
p. 110
• Carbon neutrality in the long-term,
pp. 111-115
• Operational excellence model, pp. 116-127
• Alliances for the promotion of local
development, pp. 127-128
• Sustainability material topics, p. 129
POLICIES
Art. 3.1, paragraph b)
RISK MANAGEMENT
MODEL
Art. 3.1, paragraph c)
• Main regulatory and guiding instruments
related to Legislative Decree 254/2016
topics, pp. 108-109
• Carbon neutrality in the long-term, pp. 111-115
• People, pp. 116-118
• Safety, p. 119
• Respect for the environment, pp. 120-122
• Human Rights, pp. 123-124
• Transparency and anti-corruption, pp. 126-127
THEMES AND FOCUSES IN THE ANNUAL REPORT (AR)
AND IN THE CORPORATE GOVERNANCE
AND SHAREHOLDING STRUCTURE REPORT (CGR)
AR
Business Model, p. 4
Responsible and sustainable approach, p. 5
Stakeholder engagement activities, pp. 14-15
Strategy, pp. 16-19
Governance, pp. 24-29
CGR Responsible and sustainable approach, pp. 8-11
Corporate Governance Model, pp. 11-13
Board of Directors: Composition pp. 35-40
and Board induction pp. 55-56
Board committees pp. 56-66
Board of Statutory Auditors, pp. 66-76
Model 231, pp. 104-106
CGR Eni regulatory system, pp. 91-104
AR
Integrated Risk Management Model, p. 20; Integrated Risk
Management Process, p. 21; Targets, risks and treatment
measures pp. 22-23; Risk factors and uncertainties, pp. 88-104
(1) For more information, see: “REPORTING PRINCIPLES AND CRITERIA”.
(2) The UN’s 2030 Agenda for Sustainable Development, presented in September 2015, identifies 17 Sustainable Development Goals (SDGs), which represent common goals for the
current complex social challenges.
107
AREAS OF THE ITALIAN
LEGISLATIVE DECREE
254/2016
PARAGRAPHS INCLUDED
IN THE NFI
THEMES AND FOCUSES IN THE ANNUAL REPORT
(AR) AND IN THE CORPORATE GOVERNANCE
AND SHAREHOLDING STRUCTURE REPORT (CGR)
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CLIMATE
CHANGE
Art 3.2, paragraph
a)
Art 3.2, paragraph
b)
PEOPLE
Art 3.2,
paragraph d)
Art 3.2,
paragraph c)
• Main regulatory and guiding instruments
related to Legislative Decree 254/2016
topics, pp. 108-109
• Organizational and management models,
AR
p. 110
• Carbon neutrality in the long-term
(governance, risk management, strategy
and objectives), pp. 111-115
Responsible and sustainable approach, p. 5
Integrated Risk Management, pp. 20-23; Safety,
security, environmental and other operational
risks, pp. 91-92; Risks related to climate change,
pp. 92-95
Strategy, pp. 16-19
CGR Responsible and sustainable approach, pp. 8-11
• Main regulatory and guiding instruments
related to Legislative Decree 254/2016
topics, pp. 108-109
• Organizational and management models,
AR
p. 110
• People (employment, diversity and
inclusion, training, industrial relations,
welfare, health), pp. 116-118
• Safety, p. 119
Responsible and sustainable approach, p. 5
Integrated Risk Management, pp. 20-23; Risks
associated with the exploration and production
of oil and natural gas, pp. 95-98; Safety,
security, environmental and other operational
risks, pp. 91-92
Governance, pp. 24-29 (Remuneration Policy,
p. 28)
RESPECT
FOR THE
ENVIRONMENT
Art. 3.2, paragraph a)
Art. 3.2, paragraph b)
Art. 3.2, paragraph c)
• Main regulatory and guiding instruments
related to Legislative Decree 254/2016
topics, pp. 108-109
• Organizational and management models,
AR
p. 110
• Respect for the environment (circular
economy, water, spills, waste,
biodiversity), pp. 120-122
Responsible and sustainable approach, p. 5
Integrated Risk Management, pp. 20-23; Risks
associated with the exploration and production
of oil and natural gas, pp. 95-98; Safety,
security, environmental and other operational
risks, pp. 91-92
HUMAN RIGHTS
Art 3.2,
paragraph e)
• Main regulatory and guiding instruments
related to Legislative Decree 254/2016
topics, pp. 108-109
• Organizational and management models,
AR
Responsible and sustainable approach, p. 5
CGR Responsible and sustainable approach, pp. 8-11
SUPPLIERS
Art 3.1,
paragraph c)
p. 110
• Human rights (risk management, security,
training, whistleblowing), pp. 123-124
• Main regulatory and guiding instruments
related to Legislative Decree 254/2016
topics, pp. 108-109
• Organizational and management models,
p. 110
• Suppliers (risk management), p. 125
TRASPARENCY
AND ANTI-
CORRUPTION
Art 3.2,
paragraph f)
• Main regulatory and guiding instruments
related to Legislative Decree 254/2016
topics, pp. 108-109
• Organizational and management models,
p. 110
AR
AR
Responsible and sustainable approach, p. 5
Responsible and sustainable approach, p. 5
Integrated Risk Management, pp. 20-23;
Risks related to legal proceedings and
compliance with anti-corruption legislation, p. 103
The internal control and risk management
• Transparency and anti-corruption,
system, p. 29
pp. 126-127
CGR Principles and values. Code of Ethics, p. 7;
Anti-Corruption Compliance Programme,
pp. 106-108
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LOCAL
COMMUNITIES
Art 3.2,
paragraph d)
• Main regulatory and guiding instruments
related to Legislative Decree 254/2016
topics, pp. 108-109
• Organizational and management models,
AR
p. 110
• Alliances for the promotion of local
development, pp. 127-128
Responsible and sustainable approach, p. 5
Integrated Risk Management, pp. 20-23; Risks
related to political considerations, pp. 98-100;
Risks associated with the exploration and
production of oil and natural gas, pp. 95-98
Annual Report 2019.
AR
CGR Corporate Governance Report 2019.
Sections/paragraphs providing the disclosures required by the Decree.
Sections/paragraphs to which reference should be made for further details.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2019
108
The new mission
Eni’s new mission – approved by the Board of Directors in
September 2019 – shows the path that the Company is taking to
face the main challenge of the energy sector: ensuring access to
efficient and sustainable energy for all, while reducing greenhouse
gas emissions, in order to combat climate change in line with the
objectives of the Paris Agreement. This mission completes and
consolidates the previous one, confirming Eni’s commitment
to an energy transition that is also socially just and organically
integrating the 17 SDGs to which Eni intends to contribute, seizing
new business opportunities.
This is made possible by Eni’s people, the Company’s passion and
the drive towards continuous innovation, the enhancement of
diversity as a lever for development, respect for, and promotion of,
human rights, integrity in business management and protection of
the environment.
Furthermore, it must be borne in mind that achieving the SDGs
requires unprecedented collaboration between the public and
private sectors. Hence Eni’s commitment in defining and building
alliances (Public-Private Partnership) with partners committed
locally and internationally recognised.
Main regulatory and guiding instruments related to Legislative Decree
254/2016 topics
In order to implement the mission in actual practice and to ensure
integrity, transparency, correctness and effectiveness in its
processes, Eni adopts rules for the performance of business
activities and the exercise of powers, guaranteeing observance of
the general principles of traceability and segregation.
All of Eni’s operational activities can be grouped into a map of
processes instrumental to the Company’s activities and integrated
with control requirements and principles set out in the compliance
and governance models and based upon the Bylaws, the Code of
Ethics, the Corporate Governance Code, the Model 231 principles, the
SOA principles3 and the CoSO Report4.
By-laws
Code of Ethics
Corporate
Governance Code
Model 231
principles
Principles of Eni’s control system
on financial reporting
CoSo Report framework
GENERAL OVERVIEW OF THE REGULATORY SYSTEM
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Policy
Management
System
Guideline
10 policies approved by the Board of Directors
- Operational Excellence; Our tangible and intangible assets; Our partners of the value chain;
Our institutional partners; The global compliance; Sustainability; Our people;
Information management; The integrity in our operations; Corporate governance.
47 Management System Guidelines (“MSG")
- 1 MSG of Regulatory System defines the process for Regulatory System management;
- 33 MSG of Process define the guidelines for properly managing the relevant process
and the related risks, with an aim towards integrated compliance;
- 13 Compliance/Governance MSGs (normally approved by the Board of Directors) define the
general rules for ensuring compliance with the law, regulations and corporate governance code;
- define the operational methods to be implemented in executing the Company’s activities;
Procedure
- define in detail the operating procedures for a specific function, organisational unit or professional
Operating Instruction
area.
The types of instruments that comprise the regulatory system are:
- Policies, approved by the Board of Directors, are mandatory
documents that define the general principles and rules of conduct
that must inspire all of Eni’s activities, in order to achieve corporate
objectives, having taken due account of risks and opportunities.
Policies cut across processes and each one focuses on a key
element of Company management. Eni Policies apply to Eni SpA and,
subject to transposition, all Eni subsidiaries;
- Management System Guidelines (“MSGs”) define the rules
common to all Eni units and may regard either processes or
compliance/governance (the latter usually approved by the
Board of Directors) and include sustainability aspects. The
individual MSGs issued by Eni SpA apply to subsidiaries, which
take steps to ensure their transposition to their organisation,
except in cases where there is a need for an exemption;
- Procedures define the operational methods to be implemented in
executing the activities of the individual companies or functional areas;
- Operating Instructions are an additional level of detail for representing
the operating procedures for a specific function, organisational unit or
professional area.
The regulatory instruments are published on the corporate intranet and,
in some cases, on the Company’s website. The Policies and MSGs have
been disseminated to subsidiaries, including listed subsidiaries, for
the subsequent phases for which they are responsible, such as formal
transposition and amendment of their existing regulatory systems.
In addition to the Policies, the table below also includes other Eni
regulatory instruments approved by the CEO and/or the Board of
Directors.
(3) US Sarbanes-Oxley Act of 2002.
(4) Framework issued by the “Committee of Sponsoring Organizations of the Treadway Commission (CoSO)” in May 2013.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION
109
CARBON NEUTRALITY
IN THE LONG TERM
CLIMATE
CHANGE
OBJECTIVE
Combat climate change
PUBLIC DOCUMENTS
“Sustainability” Policy, Eni’s Position on
biomass, Eni’s responsible engagement on
climate change within business associations
PRINCIPLES:
• reduce greenhouse gas emissions by improving
the efficiency of plants and increasing the use of
low carbon fuels
• develop and implement new technologies for
the reduction of greenhouse gas emissions and
more efficient energy production
• develop flexible mechanisms and instruments to
reduce deforestation
• promote sustainable water resource
management
• ensure sustainable biomass management
throughout the supply chain
• ensure consistency and transparency in the
activities of associations with Eni’s strategy on
climate change and energy transition, in line
with stakeholders’ expectations
OPERATIONAL
EXCELLENCE MODEL
PEOPLE, HEALTH
AND SAFETY
OPERATIONAL
EXCELLENCE MODEL
RESPECT FOR
THE ENVIRONMENT
OBJECTIVE
Valorize Eni’s people and protect their health and
safety
OBJECTIVE
Use resources efficiently and protect biodiversity
and ecosystem services (BES)
PUBLIC DOCUMENTS
“Our People” and “The integrity in Our Operations”
policies, Eni’s Statement on Respect for Human
Rights
PRINCIPLES:
• respect the dignity of each individual, valuing
cultural, ethnic, gender, age, sexual orientation
and different abilities
• provide managers with tools and support for
the management and development of people
working for them
• identify knowledge instrumental to
the Company’s growth and promote its
enhancement, development and sharing
• adopt fair remuneration systems that allow to
motivate and retain people with skills that best
suit the needs of the business
• carry out activities in accordance with
agreements and regulations on workers’ health
and safety protection and in accordance with the
principles of precaution, prevention, protection
and continuous improvement
PUBLIC DOCUMENTS
“Sustainability” and “The integrity in Our Operations”
policies, “Eni biodiversity and ecosystem services”
policy, “Eni’s commitment not to conduct oil and gas
exploration and development activities within the
boundaries of Natural Sites included in the UNESCO
World Heritage List”, “Eni’s positioning with regards
to Green Sourcing”
PRINCIPLES:
• consider, in project assessments and during
the operations, the presence of UNESCO World
Heritage Natural Sites and other protected areas
relevant to biodiversity, identifying potential
impacts and mitigation actions (risk-based
approach)
• establish links between environmental and social
aspects including the sustainable development of
local communities
• promote sustainable water resource management
• promote Green Sourcing principles
• optimise the control and reduction of emissions
into the air, water and soil
OPERATIONAL
EXCELLENCE MODEL
OPERATIONAL
EXCELLENCE MODEL
ALLIANCE FOR
LOCAL DEVELOPMENT
HUMAN
RIGHTS
OBJECTIVE
Protect human rights
PUBLIC DOCUMENTS
“Sustainability”, “Our people”, “Our Partners of
the Value Chain”, “The integrity in our operations”
policies, Code of Ethics; Eni’s Statement on
Respect for Human Rights, “Whistleblowing reports
received, including anonymously, by Eni SpA and
by its subsidiaries in Italy and abroad”
PRINCIPLES:
• respect human rights and promote their
respect among employees, partners and
stakeholders, also through training and
awareness-raising activities
• ensure a safe and healthy working
environment and working conditions in line
with international standards
• take into account Human Rights issues, from
the very first feasibility evaluation phases of
projects and respect the distinctive rights of
indigenous populations and vulnerable groups
• select partners who comply with the Code of
Ethics and who are committed to preventing
or mitigating impacts on human rights
• minimize the necessity for intervention by
state and/or private security forces to protect
employees and assets
TRANSPARENCY AND
ANTI-CORRUPTION
LOCAL
COMMUNITIES
OBJECTIVE
Combat active and passive corruption
PUBLIC DOCUMENTS
“Anti-Corruption” Management System
Guideline, “Our partners of the value chain”
policy, Tax Strategy Guideline
OBJECTIVE
Promote relations with local communities and
contribute to their development
PUBLIC DOCUMENTS
“Sustainability” policy,
Eni’s Statement on Respect for Human Rights
PRINCIPLES:
• carry out business activities with fairness,
correctness, transparency, honesty and
integrity in compliance with the law
• prohibit bribery without exception
• prohibit offering, promising, giving, paying,
directly or indirectly, benefits of any nature
to a Public Official or a private person (active
corruption)
• prohibit accepting, directly or indirectly,
benefits of any nature from a Public Official or
a private person (passive corruption)
• ensure that all Eni employees and partners
comply with anti-corruption regulations
PRINCIPLES:
• create growth opportunities and enhance the
skills of people and local companies in the
territories where Eni operates
• involve local communities in order to consider
their concerns on new projects, impact
assessments and development initiatives,
also with reference to human rights
• identify and assess the environmental,
social, economic and cultural impacts
generated by Eni activities, including those
on indigenous populations
• promote prior, free and informed consultation
with local communities
• cooperate in initiatives to guarantee
independent, long-lasting and sustainable
local development
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2019 110
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DIMENSION
ORGANIZATIONAL AND MANAGEMENT MODELS
• Evaluation for Medium and Long Term Plans Committee, chaired by the CEO, which devised a Medium/ Long-Term plan for business
sustainability to 2050
CLIMATE
CHANGE
• Energy Solutions Department: dedicated to energy production from renewable sources
• Central organizational function which oversees the strategy and positioning on climate change
• Energy Transition Research and Development Program: it aims to develop technologies to promote the rapid spread of natural gas
usage, decarbonizing the supply chain
• Energy management systems coordinated with the ISO 50001 standard, included in the HSE regulatory system, for the improvement
of energy performance and already implemented in all the main Mid-Downstream sites and extension to all Eni in progress
PEOPLE
• Employment management and planning process to align skills to the technical and professional needs
• Human resources management and development tools, aimed at professional growth and involvement, intergenerational
exchange of experiences, building of cross-cutting managerial development pathways in core technical areas and valuing
diversity
• Working group to determine the impacts of Digital Transformation on Roles/Skills. Development of Innovative Tools to support HR
Management processes
• Quality management system for training, up-to-date and complying with the ISO 9001:2015 standard
• Knowledge management system for integrating and sharing know-how and professional experiences
• National and international industrial relations management system: participative model and platform of operating tools to
motivate and engage employees in compliance with ILO(a) conventions and the guidelines of the Institute for Human Rights and
Business
• Integrated environmental, health and safety management system based on an operating platform of qualified healthcare providers
and partnerships with national and international university and governmental research centers and institutions
• Welfare system for the achievement of work-life balance and the enhancement of services for employees and their families
• Integrated environment, health and safety management system with the aim of eliminating or mitigating the risks to which workers
are exposed during their work activities
SAFETY
• Process safety management system aimed at preventing major accidents by applying high technical and management standards
(application of best practices for asset design, operating management, maintenance and decommissioning)
• Emergency preparation and response with plans that put the protection of people and the environment first
• Product safety management system for the assessment of risks related to the production, import, sale, purchase and use of
substances/mixtures to ensure human health and environmental protection throughout their life cycle
• Integrated environment, health and safety management system: adopted in all plants and production units in accordance with the
ISO 14001:2015 environmental management standard
RESPECT FOR THE
ENVIRONMENT
• Application of the Environmental, Social & Health Impact Assessment (ESHIA) process to all projects
• Technical meetings for the analysis and sharing of experiences on specific environmental and energy issues
• Green Sourcing: model to identify analysis methods and technical requirements for the selection of products and suppliers with the
best environmental performances
• Site-specific circularity analysis: mapping of circularity elements already in place and identification of possible improvements at
HUMAN RIGHTS
site level
• Biomasses Working Group: implementation of the commitments set out in Eni’s Position on biomass and palm oil
• Human rights management process regulated in a Management System Guideline
• Inter-functional activities on Business and Human Rights to further align processes with key international standards and best
practices
• Application of the ESHIA process to all projects, integrated with the analysis of human rights impacts
• Specific analyses of human rights impacts known as HRIA (Human Rights Impact Assessment)
• Security management system aimed at ensuring protection for Eni’s people in all the Countries in which Eni operates and particularly
in high-risk Countries
TRANSPARENCY
AND
ANTI-CORRUPTION
• Model 231: sets out responsibilities, sensitive activities and control protocols for crimes of corruption under Italian Legislative Decree
231/01 (including environmental crimes and crimes relating to workers’ health and safety)
• Anti-Corruption Compliance Program: system of rules and controls to prevent corruption crimes
• Recognition for the Anti-Corruption Compliance Program: certified pursuant to the ISO 37001:2016 standard
• “Anti-Corruption Compliance” organizational structure under the “Integrated Compliance” Dept. and reporting directly to the CEO
SUPPLIERS
LOCAL
COMMUNITIES
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• Procurement Process designed to check compliance with Eni’s requirements for ethical conduct and trustworthiness, health,
safety, and environmental protection and human rights, through the qualification, selection, management and monitoring of
suppliers, as well as through assessment using parameters set out by the Social Accountability Standard (SA8000)
• Sustainability focal point at local level, who interfaces with the Company headquarters to define local community development
programs in line with national development plans and integrated into the business processes
• Application of the ESHIA process to all business projects
• Stakeholder Management System Platform for the management and monitoring of the relations with local and other stakeholders and
of grievances
• Risk identification, mitigation and monitoring system linked to relations with local stakeholders
• Sustainability management process in the business cycle and design specifications according to international methods (e.g. Logical
Framework)
INNOVATION AND
DIGITALIZATION
• Centralized Research & Development Function for optimal sharing and valorisation of know-how
• Management of Technological Innovation projects in line with R&D best practices (planning and control for the steps following the
development of the technology)
• Continuous updating of procedures relating to the protection of intellectual property and the identification of professional R&D service
providers
(a) International Labour Organization.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION
111
CARBON NEUTRALITY
IN THE LONG-TERM
Aware of the scientific evidences of climate change reported
by the Intergovernmental Panel on Climate Change (IPCC), Eni
intends to play a leadership role in the energy transition process,
supporting the objectives of the Paris Agreement. Eni has long
been committed to promoting comprehensive and effective climate
change disclosure and in this respect confirms its commitment to
implementing the recommendations of the Task Force on Climate
Related Financial Disclosure (TCFD).
Leadership in disclosure - Eni is the only O&G company
involved in the Financial Stability Board’s Task Force on Climate
Related Financial Disclosure (TCFD) since the beginning of its
work and has contributed to the development of the voluntary
recommendations for corporate climate change reporting.
Transparency in climate change reporting and the strategy
implemented by the Company have allowed Eni to be, once again
in 2019, a leading company with an A- rating in the Climate Change
disclosure program of the CDP (formerly Carbon Disclosure Project,
recognised internationally as one of the reference institutions
for assessing climate performance and strategies of listed
companies). The rating achieved by Eni was equalled by only a
few other companies in the Oil & Gas industry and far exceeds the
global average which has stabilised at a rating of C, in a rating scale
ranging from D (minimum) to A (maximum). As further proof of its
commitment and transparency, Eni’s climate disclosure included
in the NFI within the Annual Report 2018 has been commended as
good practice with reference to governance, risk management, and
metrics and targets in the TCFD Good Practice Handbook by SASB
(Sustainability Accounting Standards Board) and CDSB (Climate
Disclosure Standards Board).
Commitment to partnerships - Among the many international
climate initiatives that Eni participates in, Eni’s CEO sits on the
Steering Committee of the Oil and Gas Climate Initiative (OGCI).
Established in 2014 by 5 O&G companies, among which Eni, the
OGCI now numbers thirteen companies, representing about one
third of global hydrocarbon production and supplying around 20% of
the global demand for energy. In 2019, OGCI published the progress
made towards the methane intensity reduction target announced
in 2018 (collective target for reducing the intensity of methane
emissions from upstream activities from 0.32% in 2017 to 0.25%
by 2025), with a collective reduction of 9% in 2018. Furthermore,
has continued the commitment to the joint investment of 1 billion
dollars in 10 years, for the development of technologies designed
to reduce GHG emissions in the global energy value chain, and in
2019 the CCUS KickStarter initiative was launched to promote wide-
scale marketing at global level of CCUS (CO2 Capture, Utilisation and
Storage) technology.
Disclosure on long-term carbon neutrality is structured around
the four thematic areas covered by TCFD recommendations:
governance, risk management, strategy, and metrics and targets.
The key elements of each area are presented below; please see the
Eni For 2019 Report – Carbon neutrality in the long-term5 for the
complete analysis.
TCFD RECOMMENDATIONS
GOVERNANCE
Disclose the organization’s
governance around
climate-related risks
and opportunities.
STRATEGY
Disclose the current and potential
impacts of climate-related risks and
opportunities on the organization’s
businesses, strategy, and financial
planning where such information is
material.
RISK MANAGEMENT
Disclose how the organization
identifies, assesses,
and manages risks related
to climate change.
METRICS & TARGETS
2019 ANNUAL REPORT
2019 SUSTAINABILITY REPORT
Consolidated Non-Financial
Information
Eni for Addendum - Carbon
neutrality in the long-term
a) Oversight by the BoD
b) Role of the management
√
Key elements
a) Climate-related risks and opportunities
b) Incidence of climate-related risks and opportunities
c) Resilience of the strategy
√
Key elements
a) Identification and assessment processes
b) Management processes
c) Integration into overall risk management
√
Key elements
√
Key elements
√
√
√
√
√
√
√
√
√
√
√
Disclose the metrics and targets used
to assess and manage risks and
opportunities related to climate
change where such information is
material.
a) Metrics used
b) GHG emissions
c) Targets
(5) This report will be published on the same day as the Shareholders’ Meeting.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2019 112
GOVERNANCE
Role of the BoD - Eni’s decarbonisation strategy is part of a
structured system of Corporate Governance where the BoD and
the CEO play a central role in managing the main issues related to
climate change. Based on CEO’s proposal, the BoD examines and
approves the Strategic Plan, which sets out strategies and targets,
including those related to climate change and energy transition.
Since 2014, the BoD has been supported in performing its duties
by the Sustainability and Scenarios Committee (SSC), with whom
it examines, on a periodic basis, integration between strategy,
future scenarios and the medium/long-term sustainability of the
business. During 2019, the SSC discussed climate change issues
in detail at all meetings, including the decarbonisation strategy,
energy scenarios, renewable energies, research and development to
support the energy transition, partnerships on climate and issues
related to water resources and biodiversity6. Since the second half
of 2017, the BoD and the CEO are also supported by an Advisory
Board composed of international experts, with the aim of analysing
the main geopolitical, technological and economic trends, including
issues related to the decarbonisation process7. Since 2018, Eni has
pledged its contribution to the World Economic Forum (WEF) “Climate
Governance” initiative8, by involving Eni’s BoD, and during 2019 took
part in other initiatives launched within the WEF, among which the
definition of a model for assessing the governance processes used
by the organization to manage risks and opportunities related to
climate change. As from 2019, the BoD examines and approves Eni’s
Medium-Long Term Plan, aiming at guaranteeing sustainability of
the business portfolio in a time frame up to 2050, in line with what is
provided for in the Four-Year Strategic Plan.
Eni’s economic and financial exposure to the risk deriving from the
introduction of new carbon pricing mechanisms is examined by the
BoD both in the approval phase leading of each investment and in the
following semi-annual monitoring of the entire project portfolio. The
BoD is also informed annually on the results of the impairment test
carried out on the main Cash Generating Units in the E&P sector and
elaborated with the introduction of a carbon tax value aligned with
IEA9 Sustainable Development Scenario - SDS (see pages 92-95).
Finally, the BoD is informed on a quarterly basis on the results of
risk assessment and monitoring activities related to Eni’s top risks,
including climate change.
Role of management. In 2019, it has been established the Evaluation
for Medium/Long-Term Plans Committee chaired by the CEO, with the
aim of supporting the organic and sustainable development of Eni’s
business, identifying strategic and operating guidelines and directing
actions to ensure achievement of decarbonisation-related targets.
The strategic commitment to carbon footprint reduction is part of
the company’s essential goals and is also reflected in the Variable
Incentive Plans for the CEO and company management. In particular,
the new 2020-2022 Long-Term Stock Incentive Plan supports the
implementation of the Strategic Plan by introducing new parameters
related to decarbonisation, energy transition and circular economy,
in line both with the targets announced to the market and all
stakeholders’ interests. The overall weighting for these targets is 35%,
both for the CEO and for all Eni managers involved in the Plan. The
Short-Term deferral Incentive Plan includes, in continuity with the
past years, the upstream GHG emissions intensity reduction, in line
with 2025 target. This target is assigned to the CEO with a weighting
of 12.5% and to all company managers according to percentages in
line with their responsibilities.
RISK MANAGEMENT
Eni has developed and adopted an Integrated Risk Management (IRM)
Model to ensure that management takes risk-informed decisions, by
assessing and analysing risks, including in the medium and long-term,
within an integrated, comprehensive and prospective vision.
The IRM process ensures detection, consolidation and analysis of
all Eni risks and supports the BoD in checking the compatibility of
risk profiles with strategic targets, including those in the medium to
long-term.
The IRM process begins with the contribution to define Eni’s medium,
long-term and Strategic Plan (e.g. definition of de-risking targets
and strategic treatment actions), and continues by supporting
the implementation of such plans through periodic cycles of risk
assessment and monitoring.
Risks are:
- assessed with quantitative and qualitative tools considering both
the probability of occurrence and the impacts that would take
place in a given time frame should the risk occur;
- represented, based on probability of occurrence and impact, by
matrices that allow comparison and classification according to
their relevance.
With a view to improving process effectiveness and efficiency and data
quality, during 2019 the following actions were taken: (i) strengthening
of risk assessment methodologies with adoption of new tools to assess
the effectiveness of mitigation actions and the economic-financial
impacts; (ii) implementation of the Integrated Country Risk (ICR) model
designed for an integrated analysis of the risks relevant to Countries
where Eni is present or those of potential interest; (iii) execution of a
pilot project for the ICR model digitalisation, which will be extended to
the main Countries with upstream activities during 2020.
The risk of climate change is identified as one of Eni’s top strategic
risks and is analysed, assessed and monitored by the CEO as part of
the IRM process.
Main risks and opportunities
Risks related to climate change are analysed, assessed and
managed by considering energy transition aspects (market
scenario, regulatory and technological evolution, reputation issues)
and physical phenomena. The analysis is carried out through an
integrated and cross-cutting approach which involves specialist
departments and business lines and includes evaluation of the
related risks and opportunities. The main findings are shown below.
Market scenario. In the International Energy Agency (IEA)
Sustainable Development Scenario (SDS10), taken as reference to
assess energy transition risks, fossil fuels are expected to continue
playing a central role in the energy mix (Oil & Gas equal to 47% of
the mix in 2040), although by 2040, the global energy demand is
expected to fall slightly compared to today (-7.2% vs. 2018, CAGR
(6) For more information, please see the “Sustainability and Scenarios Committee” section of the 2019 Corporate Governance Report.
(7) For more information, please see the “Governance” chapter on pages 24-29.
(8) The initiative aims to raise the Boards’ level of awareness on climate-related issues, also in response to recommendations by the Task Force on Climate-related Financial
Disclosures (TCFD).
(9) International Energy Agency.
(10) World Energy Outlook (WEO) 2019.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION 113
2018-40 -0.3%). Natural gas is expected to increase its share of the
mix (24% in 2040 vs. 23% in 2018) even in the SDS. In fact, due to
its lower carbon intensity and better environmental performance,
natural gas is the fossil fuel with the higher future perspectives,
both by integration with renewable sources and substituting
sources with higher environmental impacts, especially in emerging
Countries. Moreover, in the future, natural gas will play an important
role within a growing hydrogen production and the implementation
of CO2 capture, utilisation and storage (CCUS) projects. Renewables
will become increasingly important in the path to decarbonisation,
succeeding in supplying 34% of primary consumption (vs. 14%
in 2018), mostly due to development of wind and solar power. Oil
demand is expected to increase in the other IEA scenarios (Current
Policies Scenario and Stated Policies Scenario), while in the SDS
scenario an immediate peak is expected globally within the next
two years, followed by a progressive drop in consumption in almost
all Countries (except India and Sub-Saharan Africa). Nonetheless,
even considering the SDS scenario, there is still a need for
significant investments in the upstream sector to compensate
for the drop in production from existing fields. There is residual
uncertainty linked to the effect that regulatory developments
and breakthrough technologies could have in this scenario. Eni
performs an assessment of the potential costs associated with GHG
emissions, according to the SDS, as detailed in the section on Risk
factors and uncertainties (pages 88-104).
Regulatory developments. Adoption of policies designed to support
the energy transition to low carbon sources could have significant
impacts on the business. Although COP25 in Madrid hasn’t defined
the rules for implementing the Paris Agreement market mechanisms,
a growing number of governments, including the EU, are announcing
the revision of targets for 2030 and setting new long-term net-
zero emission targets, showing greater commitment in facing the
exceptional challenges in the development of low-carbon energy
solutions. In particular, with the presentation of the new “European
Climate Law”, the European Union has set itself the target of reaching
carbon neutrality by 2050, as enactment of the proposal for the new
European Green Deal, presented in December 2019. Also in light of
this development, Eni has defined a medium to long-term plan to take
full advantage of the opportunities offered by the energy transition
and progressively reduce the carbon footprint of its activities, as
explained in more detail in the Strategy and Objectives section.
Technological developments. The need to build a final energy
consumption model with a low carbon footprint, will incentivize
technologies aimed at capturing and reducing GHG emissions,
producing hydrogen from gas as well as technologies for
minimization of methane emissions along the Oil & Gas production
value chain. These elements will support the role of hydrocarbons in
the global energy mix. On the other hand, technological development
in the field of renewable energy production and storage and efficiency
of electric vehicles may impact the demand for hydrocarbons and
therefore the business. Scientific and technological research is hence
one of the levers of Eni’s decarbonisation strategy; main areas of
action are described in the Strategy and Objectives section.
Reputation. Awareness-raising campaigns by NGOs and other
environmentalist organisations, media campaigns, shareholder
resolutions during meetings, disinvestments by some investors
and class action by groups of stakeholders are more and more
oriented towards greater transparency on the tangible efforts made
by Oil & Gas companies for energy transition. Furthermore, some
public and private parties have brought proceedings, both legal and
otherwise, against the major Oil & Gas companies, including Eni
Group companies, claiming their responsibility for impacts related
to climate change and human rights. Eni has long been committed
to promoting a constant, open and transparent dialogue on climate
change and human rights issues which are an integral part of its
strategy and therefore subject of communications to all stakeholders.
This commitment is part of a wider relationship that Eni has
established with its stakeholders on important sustainability issues,
with initiatives focused on governance, dialogue with investors
and targeted communication campaigns, as well as participation
in international initiatives and partnerships. In the early months of
2020, upholding requests from a number of investors, Eni published
a Policy on Responsible Engagement on climate change within
business associations, in which it commits to check periodically on
consistency between its climate and energy advocacy positions and
those of the trade associations in which is involved.
Physical risks. Increasingly intense extreme/chronic climate
phenomena in the medium to long term could damage plants
and infrastructures, resulting in an interruption of industrial
activities and increased recovery and maintenance costs. In
relation to extreme phenomena, such as hurricanes or typhoons,
Eni’s current portfolio of assets, designed in accordance
with current regulations to withstand extreme environmental
conditions, has a geographical distribution that does not lead to
concentrations of risk. The vulnerability of Eni assets to more
gradual phenomena, such as rising sea levels or coastal erosion,
is limited and it is therefore possible to identify and implement
preventive mitigation measures. In addition to its commitment
to ensure integrity of its operations, Eni is active on the issues
of climate change adaptation, including aspects related to social
and environmental impacts, with particular focus on assessing
major vulnerabilities linked to physical risks and developing
suitable guidelines for the implementation of adaptation actions
in Countries where Eni has interests.
STRATEGY AND OBJECTIVES
Eni’s strategy combines objectives of continuous growth in a fast
developing energy market with a significant reduction of the Group’s
carbon footprint. In the future, Eni will be even more sustainable, it
will have a stronger role as a global player in the energy scenario and
will benefit from the progressive development of business areas such
as renewables and circular economy.
The result of its industrial strategy will lead to an 80% reduction in net-
absolute11 emissions by 2050, well above the 70% target indicated
by IEA in the SDS compatible with the Paris Agreement, and to a 55%
reduction in the emission intensity12.
(11) Net-absolute GHG Lifecycle emissions: these are all the Scope 1, 2 and 3 emissions associated with our operations and products, throughout their value chain, net of carbon sinks.
(12) Ratio between net-absolute GHG emissions (Scopes 1, 2 and 3) throughout the lifecycle of energy products and the quantity of energy included in them.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2019 114
In order to monitor these targets, Eni has developed a rigorous
method inclusive of all GHG emissions. This method includes all
scope 1, 2 and 3 emissions, in absolute and relative terms, linked
to the energy products sold, whether from our own production or
purchased from third parties. This distinctive approach exceeds
current standards for detection of emissions and provides a complete
representation of the Group’s carbon footprint. The method has been
reviewed by independent experts at the Imperial College London
(through Imperial Consultants), while the result of its application has
been audited by RINA, an independent certification company.
Actions that will help to achieve these targets include:
- progressive reduction of hydrocarbon production and a growing
incidence of gas production;
- focus on equity gas sales combined with projects for the
capture and storage of CO2 and a progressive reduction
of non-equity gas sales;
- conversion of European refineries into plants for production of
hydrogen and recycling of waste materials;
- creation of primary and secondary forest preservation projects to
compensate for around 30 million tonnes/year of CO2 by 2050;
- development of projects for capture and storage of 10 million
tonnes/year of CO2 by 2050, with an initial project under study
for the Ravenna hub in Italy, where it will be possible to channel
the CO2 captured from neighbouring industrial facilities and power
plants into gas fields that are now depleted;
- achieving a capacity for energy production from renewable sources
over 55 GW by 2050;
- expansion of retail operations with the aim of reaching over 20
million supply contracts by 2050.
Furthermore, Eni has confirmed and further extended its
intermediate decarbonisation targets: net-zero carbon footprint by
2030 for scope 1 and 2 emissions from upstream operations and
net-zero carbon footprint for scope 1 and 2 emissions from all Group
operations by 2040.
Overall spending in the four-year period 2020-23 for decarbonisation,
circular economy and renewables is forecast at approximately €4.9
billion, including scientific and technological research activities
designed to support these areas.
PERFORMANCE METRICS AND COMMENTS
Eni has defined indicators that show the progress achieved so far
in the reduction of GHG emissions into the atmosphere, the use and
consumption of energy from primary sources and the production of
energy from renewable sources. With specific reference to short-term
decarbonisation targets, defined on operated assets and accounted
on a 100% basis, the following is a summary of the results achieved
in 2019 and of the progress towards the targets:
Reduction of the upstream GHG emissions intensity index of 43%
by 2025 against 2014: the upstream GHG intensity index, expressed
as a ratio between direct emissions in tonnes of CO2eq and gross
production in thousands of barrels of oil equivalent, in 2019 improved
by 9% over 2018, with a value of 19.58 tonnesCO2eq/kboe. The overall
reduction against 2014 is 27% in line with the 2025 target. This index
improvement is linked to the increase in production at new low
emissions intensity plants (e.g. Zohr in Egypt and OCTP - Offshore
Cape Three Points in Ghana), consolidation of the contribution to
reduction of process flaring linked to projects launched during 2018,
as well as to completion of methane fugitive emissions monitoring
campaigns and planned leak repairs in 2019.
Zero process gas flaring by 2025: in 2019, the volumes of
hydrocarbons sent to process flaring, equal to 1.2 billion Sm3,
decreased by 15% against 2018 and by 29% against 2014, in relation
to the contribution of specific flaring down projects (Libya, Nigeria,
Turkmenistan) and the decrease of production that involved a number
of fields with associated gas flaring. In 2019, Eni invested €31 million in
flaring down projects, in particular in Libya and in Nigeria.
Reduction of upstream fugitive methane emissions of 80% by
2025 against 2014: in 2019, upstream fugitive methane emissions
were 21.9 kton CH4, decreasing by 44% against 2018, due to Leak
Detection and Repair (LDAR) campaigns carried out in the assets
at Zohr (Egypt) and Jangkrik (Indonesia) and improved accounting
approach for El Feel and Bouri (Libya). The reduction achieved has
made it possible to attain the 2025 target six years in advance.
The LDAR campaigns also involved the midstream sector (Sergaz),
where they led to a reduction of 35% in fugitive emissions compared
to 2018.
Average improvement of 2% per year in 2021 compared to 2014 of
carbon efficiency index: the target has extended the commitment to
reducing GHG emissions intensity to all business areas. This objective
refers to an overall Eni index, maintaining the appropriate flexibility in
the trends of the individual businesses. In 2019, the index was 31.41
tonnesCO2eq/kboe, a 7.4% decrease against 2018 (33.90 tonnes of
CO2 eq/kboe) due to the contribution to reduction of the upstream
sector and an improvement of around 2% of the EniPower and Refining
& Marketing performance indexes. Although the target for reduction set
for 2021 has already been achieved, Eni will continue to strive towards
progressive improvement over the coming years.
In 2019, Eni has proceeded with the investment plan both in
projects aiming directly at increasing energy efficiency of assets
(over €8 million) and in development and revamping projects with
significant impacts on the energy performance of businesses. The
actions taken during the year, when fully operational, will allow fuel
savings of 303 ktoe/year (mainly in the upstream sector), to which
25 GWh/year of savings on purchases of electricity and steam must
be added. The benefit in terms of lower emissions will be around 0.8
million tonnes of CO2eq.
Overall, direct GHG emissions deriving from Eni operated activities
were, in 2019, 41.20 mln tonnes CO2eq, a reduction of 5% against
2018 and 29% against 2010. Such reduction is mainly due to the drop
in emissions from combustion and process as a result of energy
efficiency projects, and to reduced fugitive and venting methane
emissions (also due to improvement of estimates following census
and detailed estimation of sources of emissions). Total emissions
due to flaring, despite reduced volumes of gases sent to process
flaring, have increased by 3.7% due to extraordinary maintenance on
gas injection compressors (in Nigeria and Congo), temporary shut-
down of plants in Libya and increase of emergency flaring in Angola
(start-up of the Agogo field), as well as actions to depressurise lines
in Nigeria following acts of sabotage.
With regard to development of electricity generated from photovoltaic,
in 2019 there was a marked increase in production compared to
2018 (66.9 GWh vs. 19.3 GWh in 2018), while the quantity of
biofuels produced in 2019 has stabilised at 256 thousand tonnes,
increasing by 17%.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION 115
For 2019, Eni’s financial commitment in scientific research
and technological development amounted to €194 million, of
which approximately €102 million was spent on investments for
decarbonisation and circular economy projects. This investment
refers to efforts for energy transition, bio-refinement, green
chemistry, renewable sources, reduction of emissions and energy
efficiency.
Key Performance Indicators
Direct GHG emissions (Scope 1)
of which: CO2equivalent from combustion and process
of which: CO2 equivalent from flaring
of which: CO2 equivalent from venting
of which: CO2 equivalent from methane fugitive emissions
Carbon efficiency index
GHG emissions/100% operated hydrocarbon gross production (upstream)
GHG emissions/Equivalent electricity produced (EniPower)
GHG emissions/Refinery throughputs (raw and semi-finished materials)
Methane fugitive emissions (upstream)
Volumes of hydrocarbon sent to flaring
of which: sent to process flaring
Indirect GHG emissions (Scope 2)
Primary sources consumption
Primary energy purchased from other companies
Electricity produced from renewable sources
(million tonnes CO2eq)
(tonnes CO2eq/kboe)
(gCO2eq/kWheq)
(tonnes CO2eq/ktonnes)
(ktonnes CH4)
(billion Sm3)
(million tonnes CO2eq)
(million toe)
Total
41.20
32.27
6.49
1.88
0.56
31.41
19.58
394
248
21.9
1.9
1.2
0.69
13.6
0.4
(GWh)
66.9
2019
2018
2017
of which fully
consolidated
entities
Total
Total
26.55
43.35
43.15
23.11
33.89 33.03
2.83
0.33
0.28
6.26
6.83
2.12
2.15
1.08
1.14
43.63
33.90 36.01
21.32
21.44
22.75
397
248
402
253
395
258
10.8
38.8
38.8
1.0
0.5
0.57
10.0
0.3
57.8
1.9
1.4
2.3
1.6
0.67
0.65
13.0
13.0
0.4
0.4
19.3
16.1
Energy consumption from production activities/ 100% operated hydrocarbon gross
production (upstream)
(GJ/toe)
1.39
n.a.
1.42
1.49
Net consumption of primary resources/ Equivalent electricity produced (EniPower)
(toe/MWheq)
0.17
0.17
0.17
0.16
Energy Intensity Index (refineries)
R&D expenditures
of which: related to decarbonization
First patent filing applications
of which: filed on renewable sources
Production of biofuels*
Capacity of biorefineries *
(*) Includes the pro-rata of installed capacity of Gela's biorefinery (720,000 tonnes/y) started in August 2019.
(%)
112.7
112.7
112.2 109.2
(€ million)
(number)
(ktonnes)
(ktonnes/year)
194
102
34
15
256
660
194
102
34
15
256
660
197.2
185
74
43
13
219
360
72
27
11
206
360
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2019 116
OPERATIONAL EXCELLENCE MODEL
The Operational Excellence Model is centred on a constant
commitment to consolidating and developing skills in line with new
business needs, enhancing its people in all areas (professional and
non-professional), and ensuring health and safety, environmental
protection, respect and promotion of Human Rights and attention to
transparency and anti-corruption.
People
Eni’s business model is based on internal expertise, an asset that
Eni has built over time with dedication and commitment and that
allows generating value in both the short and long term. In the
next few years, Eni will continue the important transformation
process started about six years ago, which combines the
development of new strategic guidelines13, from the circular
economy to activities related to decarbonization, also seizing the
opportunities offered by Digital Transformation.
A culture of plurality and the development of people. Eni
operates on an international scale. Its people are citizens of the
world who live alongside the communities with which they work,
which is why plurality is an essential value. Diversity is a value-
creating resource that must be safeguarded and promoted both
within the Company and in all relationships with its stakeholders.
For this reason, Eni promotes the development of local people
through selection and professional development processes
and relies on geographical mobility as an important experience
in their professional and personal growth, ensuring uniform
management at a global level. With regard to gender diversity,
Eni pays particular attention to the promotion of initiatives to
attract female talents at a national and international level, and
to the development of managerial and professional growth paths
for the women in the Company. In this context, Eni organizes
initiatives for high school students in STEM (Science, Technology,
Engineering and Mathematics) subjects, with a focus on gender
equality (Think About Tomorrow) and participates in national and
international initiatives14 with the aim of constantly enhancing
its processes and operating practices with a view to gender
equality. Eni also regularly monitors the pay gap between the
female and male population for the same position and seniority
and has found that wages are substantially aligned. Pursuant
to International Labour Organization (ILO) standards, Eni also
carries out statistical analyses on the remuneration of local
employees.The results show that the minimum levels set by Eni
are significantly higher than the local market minimums. Eni
has also implemented managerial development and excellence
pathways aimed at the core professional areas, which it supports
through training activities, mobility initiatives, job rotation and
development tools. In particular, mobility initiatives are offered
to the managerial and non-managerial population, in order to
maximise opportunities for cross-cutting enhancement and
growth. Eni uses various assessment tools to support these
pathways, including the annual review and the performance
and feedback process with a focus on senior managers, middle
managers and young graduates. In 2019, 93% of the target
population was covered by the performance assessment process.
Training. Training is given to Eni’s people around the world to
create shared values and a common culture. Considering its
people’s skills which are essential to operational excellence, Eni
plans and implements training courses for delivery in a universal
and cross-cutting manner, projects for professional families and
specialist initiatives for strategic activities with a high technical
content. The training campaign aimed at spreading the culture
of asset integrity and increasing the level of commitment and
awareness of each person was particularly significant. Training
needs are mapped and evaluated annually according to specific
needs. With reference to the global scenario and the ongoing
digitalisation process, initiatives aimed at developing, using
and updating the most innovative technological solutions in
the operational processes continued in 2019. The development
and enhancement of digital skills continued through the
expansion and increased use of the in-house platform “Digital
Transformation Center”. To facilitate the training and education
of operators and emergency teams on safety scenarios, in
addition to the training normally carried out in the classroom and
in the field, the “Virtual Reality Training” methodology has been
consolidated, which allows delivering training through immersive
virtual reality systems both in HSE and drilling.
Industrial relations. Eni maintains ongoing relations with
national and international trade union organizations for the
conclusion and renewal of agreements with its counterparts. At
international level, the model of trade union relations is based
on three pillars: two in Europe (the European Works Council
and the European Observatory for the Health and Safety of
Workers at Eni) and a global one, namely the Global Framework
Agreement on International Industrial Relations and Corporate
Social Responsibility, which was renewed in 2019. As regards
international labour law, a mapping of the state of ratification of
the main ILO Conventions in the Countries where Eni operates
was completed and disseminated internally, thus confirming
Eni’s commitment to the fundamental principles set out therein.
Furthermore, with regard to the fundamental principle of freedom
of association, in 2019, a review of existing legislation in the main
Countries where the Company operates was carried out to ensure
that local legislations, while protecting such a principle, allow the
establishment of trade unions and workers’ representatives and
(13) For more information on the strategy, see pages 16-19; 113-114.
(14) Inspiring Girls Project - International project against stereotypes about women; “Manifesto for women’s employment” by Valore D - Programme document to enhance female talent
in businesses promoted by Valore D and sponsored by the Italian Presidency of G7 and the Department for Equal Opportunities of the Italian Prime Minister’s Office; Elis - Sistema Scuola
Impresa Consortium; WEF - World Economic Forum; ERT - European Round Table.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION 117
collective bargaining. Where local regulations do not provide for
express prohibitions, Eni always recognizes the best favourable
conditions from among those established by the ILO and local
regulations.
Parenthood, Welfare and Inclusion. Eni has continued to develop
policies to foster parenthood and families in order to ensure
increasingly greater attention to inclusion and support in cases
of disability and to consolidate services for work-life balance. In
addition to the maternity and paternity support policy promoted
in 2018 at international level, which granted 10 days of leave paid
100%, in 2019 smart working in Italy was extended to all workers
at non-operational sites, as well as to all new parents, disabled
people and caregivers. In addition, during 2019, the prevention
program continued to be extended to new sites by providing
employees with specialist visits and check-up protocols.
Health. Eni considers health protection an essential requirement
and promotes the physical, psychological and social well-being of
Eni’s people, their families and the communities of the Countries
of presence. The extreme variability of working contexts requires
a constant effort to update health risk matrices and makes it
particularly challenging to guarantee health at every stage of
the business cycle. To rise to this challenge, Eni has developed
an operational platform that ensures services to its people,
covering occupational health, industrial hygiene, traveller
health, healthcare and medical emergency, as well as health
promotion initiatives for Eni’s people and the communities in
which it operates. In 2019, all of the Group companies continued
the implementation of health management systems with the
objective of promoting and maintaining the health and well-being
of Eni’s people and ensuring adequate risk management in the
workplace.
METRICS AND COMMENTS
Overall employment amounts to 31,321 people, of whom 21,078
in Italy (67.3% of Eni employees) and 10,243 abroad (32.7% of
Eni employees). In 2019, employment at global level increased
by 371 people compared to 2018, equal to +1.2%, with an
increase in Italy (+502 employees) and a reduction abroad
(-131 employees) due mainly to corporate reorganizations15.
Overall, in 2019, 2,199 hires were made, of which 1,855 with
permanent contracts. Of these, 32.3% covered female staff
and about 81% regarded employees under 40 years of age.
Of the total number of hires, approximately 32% were in the
upstream business area (total 709, of which 547 were with
permanent contracts and 162 with fixed-term contracts),
22% in the Support Function area, 12% in the R&M&C area
and 34% in the other business areas. Overall, 1,546 contracts
were terminated, 1,198 of which were permanent contracts16,
and 23.2% regarded female employees. In 2019, 24.1% of the
permanent contracts terminated involved employees under
the age of 40. In 2019, the percentage of women in positions
of responsibility rose to 26.05%, compared to 25.28% in 2018;
overall, women accounted for 24.23% of Eni’s total workforce.
In 2019, the percentage of female employees stood at: 15.6%
senior managers, 27.2% middle managers, 29.8% white collars,
2% blue collars. Compared to the past, the overall percentage
of women on the boards of directors and statutory auditors of
subsidiaries fell slightly in 2019 to 29% and 37%, respectively. In
Italy, 1,300 people were hired, of whom 1,254 with permanent
contracts (32.7% women, up about 4 percentage points
compared to 2018); there was an increase in the younger age
group (18-29) as a result of the recruitment plan implemented
to ensure a structure consistent with business and innovation
objectives, as well as to seize the opportunities offered by
new technologies. In 2019, the number of terminations in
Italy amounted to 831, of which 707 permanent contracts (of
which 18.1% were women). Abroad, in 2019, there were 899
hires, of which 601 were with permanent contracts (31.4%
women) and 68.1% were employees under 40 years of age.
About 50% of permanent hires were in the upstream (mainly in
the United States, United Kingdom, Mexico, Angola) and R&M
business areas (Ecuador, Germany, France), with the aim of
both developing and supporting new initiatives and managing
turnover to support the consolidation and evolution of skills. As
regards terminations, 715 contracts were terminated, of which
491 were permanent. Of these, 40.1% regarded employees
under the age of 40, and 30.5% were women. The balance
between hires and terminations abroad at year-end was +184
(+899 new hires and -715 terminations) and this trend is
mainly due to the consolidation of the upstream business, as
well as widespread recruitment to support the activities of the
other business areas. Outside of Italy, as a result of the sale of
Agip Oil Ecuador, the number of local employees decreased by
252 people compared with the previous year, resulting in a drop
in the percentage of local staff out of total employment abroad
from 82.6% in 2018 to 81.2% in 2019. A total of 1,923 expatriates
(of whom 1,360 are Italian) work abroad, slightly up from 2018
(+99 Italians). The average age of Eni’s people in the world is
45.4 years (unchanged compared to 2018; 46.4 in Italy and
43.3 abroad): 49.4 years (50.3 in Italy and 47.0 abroad) for
senior and middle managers, 44.1 years (45.4 in Italy and 41.3
abroad) for white collars, and 41.3 years (40.0 in Italy and 43.0
abroad) for blue collars.
In 2019, distance learning (also through the Digital
Transformation Center platform) and a resumption of classroom
training gave a significant boost to the number of training hours
delivered, equal to +16.5% compared to 2018.
In the field of health, the number of health services delivered
by Eni in 2019 amounted to 487,360, of which 312,490 for
employees, 72,268 for family members, 94,130 for contractors
and 8,472 for others (e.g., visitors and external patients).
The number of participants in health promotion initiatives
in 2019 was 205,373, of whom 97,493 were employees,
78,330 contractors and 29,550 family members. As concerns
occupational illnesses, claims fell during 2019 from 81 to 73,
with an overall reduction of 10%, due to the reduction of illnesses
reported, both by former employees (from 71 to 64 claims) and
current employees (from 10 to 9 claims). Of the 73 occupational
disease claims submitted in 2019, 16 were submitted by heirs
(all relating to former employees).
(15) In particular, it is noteworthy the sale of Agip Oil Ecuador.
(16) Of which about 50% for retirement and 37% for resignation.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2019 118
Key Performance Indicators
Employees as of December 31(a)
(number)
Women
Italy
Abroad
Africa
Americas
Asia
Australia and Oceania
Rest of Europe
Employees aged 18-24
Employees aged 25-39
Employees aged 40-54
Employees aged over 55
Local employees abroad
Employees by professional category:
Senior managers
Middle managers
White collars
Blue collars
Employees by educational qualification:
Degree
Secondary school diploma
Less than secondary school diploma
Employees with permanent contracts(b)
Employees with fixed term contracts(b)
Employees with full-time contracts
Employees with part-time contracts(c)
Number of new hires with permanent contracts
Number of terminations of permanent contracts
Local senior managers & middle managers abroad
Seniority
Senior managers
Middle managers
White collars
Blue collars
Presence of women on the Boards of Directors
Presence of women on the Boards of Statutory Auditors(d)
Training hours
Average hours of training per employee by employee category
Senior managers
Middle managers
White collars
Blue collars
Employees covered by collective bargaining
Italy
Abroad
Occupational illnesses allegations received
Employees
Previously employed
(%)
(years)
(%)
(number)
(%)
(number)
2019
31,321
7,590
21,078
10,243
3,371
1,005
2,662
88
3,117
564
9,289
13,824
7,644
8,320
1,021
9,387
16,050
4,863
15,375
13,184
2,762
30,571
750
30,785
536
1,855
1,198
16.65
22.78
20.00
16.73
13.55
29
37
1,362,182
43.6
51.0
42.0
43.9
44.3
83.03
100
40.91
73
9
64
2018
30,950
7,307
20,576
10,374
3,374
1,257
2,505
90
3,148
437
9,224
14,058
7,231
8,572
1,008
9,147
15,839
4,956
14,603
13,348
2,999
30,183
767
30,390
560
1,264
1,270
16.70
22.12
20.02
17.03
13.05
33
39
1,169,385
36.9
41.7
37.2
36.2
37.7
80.89
100
35.33
81
10
71
2017
32,195
7,580
20,468
11,727
3,303
1,216
2,418
114
4,676
364
9,761
15,022
7,048
10,010
990
9,043
16,600
5,562
14,802
14,300
3,093
31,609
586
31,612
583
992
1,312
15.68
22.08
20.01
17.02
13.05
32
37
1,111,112
34.2
31.7
35.7
34.5
31.6
81.96
100
44.54
120
12
108
(a) The data differ from those published in the Annual Report (see inside cover) because they include only fully consolidated companies.
(b) The breakdown of fixed-term/permanent contracts does not vary significantly either by gender or by geographical area except for China and Mozambique where it is common practice to
insert local resources for fixed term and then stabilize them over a period of 1-3 years.
(c) There is a higher percentage of women (7% of total women) on part-time contracts, compared to men who are round 0.2% of total men.
(d) Outside of Italy, only the companies with a control body similar to the Italian Board of Statutory Auditors are considered.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION
119
Safety
Eni is constantly engaged in research and development for all the
necessary actions to be taken to ensure safety at work, in particular
in the development of organisational models for risk assessment and
management and in the promotion of a culture of safety, in order to
pursue its commitment to eliminating the occurrence of incidents. To
this end, in 2019, initiatives continued for both Eni and contract staff
to spread a culture of safety and in particular to encourage correct
and safe behaviours to be implemented in every aspect of life. The
“Safety starts @ office” campaign, which followed on from the 2018
“Safety starts @ home” campaign, was launched to promote safety
in offices and headquarters starting from the “Safety Golden Rules”17
(the 10 golden rules for safety at work, which came into force in
2018). The “I Live Safe” initiatives, days dedicated to research and the
implementation of practical tools for creating healthy and safe habits,
continued at operational sites; this year a modular training course
was experimented in the following thematic areas: road safety, home
safety and leisure safety with the active involvement of Company
representatives.
In the upstream foreign subsidiaries, the “HSE Personal Commitment
Program” initiative was implemented; it pursues Eni’s commitments
in the field of safety and is aimed at consolidating the leadership and
commitment, at all levels, of the management of both Eni and its
contractors, in order to spread the culture of safety and engage partners.
In particular, as regards the management of contractors at Eni’s
industrial sites, in 2019 control activities in the field were further
strengthened through the more than 130 members of the Safety
Competence Center (SCC)18, assigned to the coordination and
supervision of the safety of work sites and contract works. More than
2,800 companies, accounting for 70% of suppliers with potential HSE
criticalities in Italy, are constantly called upon to raise awareness to
build their safety culture and are monitored and evaluated through
tools set out and implemented by the SCC. Non-conformities found
are immediately redressed with corrective actions and good practices
are recognized, shared and disseminated. In 2019, work continued
on the implementation of SCC tools and methodologies abroad in
Pakistan and Tunisia.
Process safety19 is a fundamental commitment for Eni and it is pursued
through the implementation of a specific management system, in line
with international standards, and monitored with dedicated audits.
As regards emergency preparedness and response, in addition to
continuous drills, particular attention has been paid to natural risk
scenarios, consolidating innovative and centralised methods for
weather and hydrologic alerts.
The main corporate objectives for safety in 2020 are: (i) the
improvement of the Severity Incident Rate (SIR), an internal weighted
internal index that measures the level of incident severity and is used
in the short-term incentive plan of the CEO and senior managers
with strategic responsibilities in order to focus Eni’s commitment on
reducing the most serious accidents; (ii) the consolidation of the Safety
Culture Program, which monitors the level of proactivity through aspects
of preventive safety management; (iii) the definition and dissemination
of the 10 Process Safety Fundamentals, the operational rules relevant
to process safety; and (iv) the extension to Italian sites of projects that
apply new digital technologies to boost safety.
METRICS AND COMMENTS
In 2019, the Total Recordable Injuries Rate (TRIR) of the workforce
improved by 3% compared to 2018. The improvement was
particularly significant for the employees’ indicator (-44%),
while the contractors’ indicator worsened due to the increase in
the number of accidents (95 vs. 82 in 2018). There were 3 fatal
accidents in the upstream sector: one employee in Italy in March
2019 registered on the Barbara F. platform off the coast of Ancona
and two contractors hit by objects in Egypt. The indicator for injuries
at work with serious consequences was affected by two injuries to
two contractors in Italy (the same event that caused the death of
the Eni employee) and an accident in which a contractor suffered a
hand injury in Egypt. In Italy, the number of total recordable injuries
decreased (37 events vs. 40 in 2018), and the total recordable
injury rate (TRIR) improved by 14%; however, the number of
accidents abroad increased slightly (77 events vs. 76 in 2018) as
did the total recordable injury rate (+2%).
Key Performance Indicators
TRIR (Total Recordable Injury Rate)
(total recordable injuries/hours worked) x 1,000,000
Employees
Contractors
Number of fatalities as a result of work-related injury
(number)
Employees
Contractors
High-consequence work-related injuries rate
(excluding fatalities)
(high-consequence work-related injuries/hours worked)
x 1,000,000
Employees
Contractors
Near miss
Worked hours
Employees
Contractors
(number)
(million of hours)
2019
2018
2017
of which fully
consolidated
entities
0.38
0.27
0.43
1
1
0
0.01
0.00
0.01
929
206.3
56.1
150.2
Total
0.34
0.21
0.39
3
1
2
0.01
0.00
0.01
1,159
334.2
92.1
242.1
Total
0.35
0.37
0.34
4
0
4
0.01
0.00
0.01
1,431
330.6
91.6
239.0
Total
0.33
0.30
0.34
1
0
1
0.00
0.01
0.00
1,550
306.3
93.1
213.3
(17) For more information, see: https://www.eni.com/en-IT/just-transition/culture-of-safety.html.
(18) Eni Center of Excellence on Safety, which supports Eni’s industrial sites in Italy and abroad in the coordination and supervision of contract works.
(19) Process Safety aims at preventing and controlling, throughout the life cycle of its assets, uncontrolled releases of hazardous substances that can become major accidents,
protecting the safety of people, environment, productivity, Company assets and reputation.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2019
120
Respect for the environment
Eni operates in very different geographical contexts, which require
specific assessments of the environmental aspects, and is committed
to strengthening control and monitoring of its activities in order to
mitigate their impacts on the environment by adopting constantly up-
to-date international technical and management good practices and
Best Available Technology. Particular attention is paid to the efficient
use of natural resources, like water; to reducing operational oil spills
and oil spills caused by sabotage; to managing waste through process
traceability and control of the entire supply chain; to managing the
interaction with biodiversity and ecosystem services, from the first
exploration stages up to the end of the project cycle.
In this scenario, the transition to a circular economy is, for Eni,
one of the main answers to the current environmental challenges,
offering, as an alternative to the traditional linear economy model, a
regenerative approach based on industrial synergy and symbiosis,
associated with a revision, through ecodesign, of the Company’s
production processes and of the management of its assets by
reducing the exploitation of natural resources and increasing the use
of materials from renewable sources (or from production scraps),
by reducing and enhancing scraps (waste, emissions, discharges)
through recycling or recovery actions, and by extending the useful
life of products and assets through reuse or reconversion actions.
In this regard, since 2017 Eni has been carrying out site-specific
circularity analyses to identify elements of circularity and
improvement measures: in 2019, Eni carried out analyses at the
multi-company sites of Bolgiano and Brindisi, at the Taranto refinery
and at the Rho depot. Interventions have therefore been identified,
some of which are already being implemented and others are in the
process of further investigation, both within the site (such as energy
or water efficiency or waste recovery) and through integration and
exchange with the surrounding area.
Eni promotes efficient water management through water risk
mitigation actions, especially in water-stressed areas, where
initiatives to reduce fresh water withdrawals and projects in the
upstream sector to give access to water are still ongoing in 2019. In
Italy, Eni is committed to increasing, over the period of the four-year
plan, the amount of groundwater reclaimed and reused for civil or
industrial purposes, to launching initiatives and assessments for
the use of poor quality water (waste water or water from polluted
groundwater, as well as rainwater and desalinated sea water)
replacing fresh water, and reducing the water use in production.
At the Val d’Agri Oil Centre (COVA) the detailed executive design of
the Mini Blue Water process was completed; it offers a treatment
capacity of about 70 m3/h, based on a proprietary technology.
The authorization process for the construction of the plant is
currently underway. Blue Water consists in an innovative process
for the treatment water used in production, which allows its reuse
for industrial purposes. Only a small proportion of Eni’s water
withdrawals comes from fresh-water sources (about 8%). The
analysis of river basin stress levels20 and in-depth studies carried
out at local level have shown that freshwater from water-stressed
areas account for less than 2% of Eni’s total water withdrawals.
In April 2019, Eni was the first company in the Oil & Gas sector
to join the CEO Water Mandate, a special United Nations initiative,
committing itself to improve the water resource management
in all its aspects, both in operations and with reference to the
use of innovative technologies, integration with the territory
and transparency. With specific regard to transparency, also
in 2019 Eni made public its answers to the CDP Water Security
questionnaire, obtaining a score of A-, which was obtained by only
two other Oil & Gas companies in the world.
As regards the management of the risk of oil spills, Eni is committed
to covering each and every aspect of its management, from
preparedness to prevention and mitigation, in line with international
best practices. As part of preparedness, i.e., to ensure the quality/
speed/effectiveness of intervention in the entire pipeline network in
Italy, a hazard analysis of natural events such as landslides and river
flooding, has been started. The objective is to identify, also using the
results of the socio-environmental sensitivity analyses, the critical
sections and the related priorities for defence interventions.
In 2019, the coating with resin/replacement of single-wall
underground tanks continued in the retail sector in Italy and will
be completed in 2020. In addition, in Egypt (JV Agiba), Eni started
a program of interventions to replace some piping and production
line sections, while in Nigeria, the installation of the e-vpms® (Eni
Vibroacustic Pipeline Monitoring System - Proprietary Patent)
instrument continued. In 2019, the experimental installation of the
TPI (Third Party Intrusion) system, an extension of the e-vpms®
instrument to two pipelines of the Italian downstream pipeline, was
started and completed, with the aim of detecting sabotage attempts
and thus making it possible to take action before a break-in takes
place. Testing of this system will continue in 2020 and, in the event of
positive results, it will be extended to other finished product pipelines
in Italy and subsequently in other Countries.
Eni’s commitment to Biodiversity and Ecosystem Services
(BES) is an integral part of the Integrated HSE Management
System, confirming its awareness of the risks for the natural
environment resulting from its sites and activities. Operating on
a global scale in environmental contexts with different ecological
sensitivities and regulatory systems, Eni manages BES through
a specific management model that has evolved over time thanks
also to long-term collaborations with recognised international
organizations that are leaders in biodiversity conservation. Eni’s
BES management model21 is aligned with the strategic objectives
of the Convention on Biological Diversity (CBD)22 and ensures that
the interactions between environmental and social aspects are
correctly identified and managed from the earliest project stages.
Eni’s biodiversity risk exposure is periodically assessed by
mapping the geographical proximity to protected areas and areas
important for biodiversity conservation. This mapping allows
(20) Water-stressed areas: areas with a Baseline Water Stress value over 40%. The indicator, defined by the World Resources Institute (WRI www.wri.org), measures the exploitation of
freshwater sources and indicates a stressful situation if withdrawals from a given river basin are greater than 40% of its renewable supply.
(21) Eni’s BES management model is described in detail in the BES Policy published on the Eni website https://www.eni.com/docs/en_IT/enicom/sustainability/Eni-Biodiversity-and-
Ecosystem-Services-Policy.pdf.
(22) Rio de Janeiro, 1992.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION 121
identifying priority sites where to take action with more detailed
surveys to characterize the operational and environmental
context and assess potential impacts to be mitigated through
Action Plans, thus ensuring effective management of risk
exposure. Moreover, in October 2019, Eni communicated the
formal commitment not to conduct oil and gas exploration and
development activities within the boundaries of Natural Sites
included in the UNESCO World Heritage List23. This commitment
confirms the policy that Eni has been following for some time in its
operations, in line with the new corporate mission, and reaffirms
both its approach to nature conservation in every area with a high
biodiversity value and the spread of good management practices in
joint ventures where Eni is not an operator.
METRICS AND COMMENTS
In 2019, seawater withdrawals dropped by 12% as a result of a
decrease of over 93 million cubic metres at the Gela refinery24 and
of reductions recorded at the Priolo, Brindisi and Porto Marghera
petrochemical plants for maintenance stops (reduction in withdrawals
of over 56 million cubic metres in total). The decline in seawater
withdrawals was also affected by the cessation of the activities of
LNG Shipping’s vessels (which contributed with over 60 million cubic
metres in 2018). Fresh water withdrawals, more than 76% of which
can be attributed to the R&M&C sector, increased by 10%, due to the
set-up that the Mantua petrochemical plant had to use during the
shutdown for the maintenance of the cooling towers and the tests on
the fire-fighting systems at the Sannazzaro refinery. The percentage
of freshwater reuse at Eni has risen to 89%. In the E&P sector, the
percentage of production water re-injected stood at 58%, down from
2018 due to maintenance work in Nigeria (Ebocha) and technical
issues in Congo (Zatchi and Loango). The number of barrels spilled
as a result of operational oil spills was more than halved compared
to 2018, particularly in Italy and Nigeria (in the latter Country through
structural interventions such as preventive maintenance or revision
of the integrated anti-corrosion plan and replacement of pipeline
sections crossing rivers or canals). The two most significant events
were recorded in Egypt (200 barrels spilled following the tipping of
a truck during a manoeuvre) and Nigeria (198 barrels spilled due to
overfilling of a tank). As regards to sabotage events, in 2019 there
was an increase in both the number and quantity of spills; all the
events concerned upstream activities in Nigeria, where the increase
in spills could be partly linked to heightened social tensions due to
the general elections. Barrels spilled as a result of chemical spills are
down considerably and are mainly attributable to upstream activities
in the UK and USA. Waste from production activities generated by Eni in
2019 decreased by 15% from 2018, due in particular to the contribution
of non-hazardous waste (78% of the total), while hazardous waste
recorded an increase. The decrease in non-hazardous waste was
recorded mainly in the E&P sector, thanks to the reduction in waste
from the development of the Zohr project in Egypt and the lower
production of onshore aquifer water in the Central-Northern
District disposed of as waste. The increase in hazardous waste,
on the other hand, was the result of drilling campaigns in Nigeria,
Kazakhstan, Angola and Pakistan. The share of recovered and
recycled waste was 7% of total disposed waste25, down from
2018, when the Zohr project ramp-up generated large quantities of
recovered waste. In 2019, a total of 4.1 million tonnes of waste was
generated by reclamation activities (of which 3.9 million tonnes
by Eni Rewind), of which about 66% was groundwater. In 2019,
€367 million was spent on reclamation activities. Emissions of
pollutants into the atmosphere are decreasing, except for NMVOC
emissions, which increased by 4% compared to 2018, particularly
in the upstream sector where the gas composition of the Bouri field
in Libya was updated, resulting in an increase in the percentage of
non-methane compounds sent to the torch.
In 2019, Eni extended the assessment of exposure to biodiversity
risk to the R&M, Versalis and EniPower operational sites, in
addition to concessions under development or exploitation in the
upstream sector, in order to identify where Eni’s activities fall,
even only partially, within protected areas26 or key biodiversity
areas (KBAs27). An analysis of the mapping of the R&M, Versalis
and EniPower operational sites showed that there is overlap, even
partial, with protected areas or KBAs at 11 sites, all located in Italy;
another 15 sites in 6 Countries (Italy, Austria, Hungary, France,
Germany and the United Kingdom) border with protected areas or
KBAs, i.e., located at a distance of less than 1 km. As regards the
upstream sector, 75 concessions overlap partially with protected
areas or KBAs (17 more than in 2018), but of these only 31
concessions (4 more than in 2018) located in 6 Countries (Italy,
Nigeria, Pakistan, Alaska, Egypt and the United Kingdom) have
operations in the overlapping area. The increase in the number of
concessions compared to last year is due to the acquisition of fields
already in production in the Beaufort Sea near the coast of Alaska.
In general, for all the business lines, the greatest exposure in Italy
is to the protected areas of the Natura 2000 Network28, which
is widespread across the Country. In no case, in Italy or abroad,
there is any overlapping of operational activities with natural
sites belonging to the UNESCO (WHS29); only one upstream site30
is located near a WHS natural site (Mount Etna) but there are no
operational activities within this protected area.
(23) Natural Sites included in the UNESCO World Heritage List as of May 31, 2019. For further details see Eni.com: https://www.eni.com/en-IT/media/press-release/2019/10/eni-makes-
no-go-commitment-for-unesco-natural-world-heritage-sites.html.
(24) The system for conveying the cooling water to the user plants was modified with the creation of a closed circuit network and resizing of the seawater lifting pump, adapting its flow
rate to the actual use.
(25) Specifically, in 2019, 10% of hazardous waste disposed of by Eni was recovered/recycled, 8% was subjected to chemical/physical/biological treatment, 19% was incinerated, 1% was
disposed of in waste dumps and the remaining 62% was sent for other types of disposal (including transfer to temporary storage plants prior to final disposal). With regard to non-hazardous
waste, 6% was recovered/recycled, 1% was subjected to chemical/ physical/biological treatment, 6% was disposed of in waste dumps and the remaining 87% was sent for other types of
disposal (including transfer to temporary storage plants prior to final disposal and incineration of small quantity).
(26) Source: World Database of Protected Areas, analysis carried out in December 2019.
(27) Source: World Database of Key Biodiversity Areas, analysis carried out in December 2019. KBAs (Key Biodiversity Areas) are sites that contribute significantly to the global
persistence of biodiversity, on land, in freshwater or in the seas. These are identified through national processes by local stakeholders using a set of globally agreed scientific criteria.
The KBAs analysed consist of two subsets:1) Important Bird and Biodiversity Areas; 2) Alliance for Zero Extinction Sites.
(28) Natura 2000 is the main tool of European Union policy for biodiversity conservation. It is an ecological network spread in the territory of the European Union, established under
Directive 79/409/EEC of 2 April 1979 on the conservation of wild birds and Directive 92/43/EEC "Habitat".
(29) WHS, World Heritage Site.
(30) Moreover, although it is not included among the consolidated entities, the Zubair field (Iraq) is located near the Ahwar site classified as a mixed WHS site (natural and cultural). In
this case too, no operational infrastructure or activity falls within this protected area.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2019 122
Key Performance Indicators
2019
2018
2017
Total water withdrawals
of which sea water
of which freshwater
of which freshwater from superficial water bodies
of which freshwater from subsoil
of which freshwater from urban net or tanker
of which polluted groundwater treated at TAF(a) plants and used in
the production cycle
of which freshwater withdrawal from other streams
of which brackish water from subsoil or superficial water bodies
Fresh water reused
Re-injected production water
Operational oil spills
Total number of oil spills (> 1 barrel)
Volumes of oil spills (> 1 barrel)
Oil spills due to sabotage (including theft)(b)
Total number of oil spills (> 1 barrel)
Volumes of oil spills (> 1 barrel)
Chemical spills
Total number of oil spills
Volumes of oil spills
Total waste from production activities
of which hazardous waste
of which non-hazardous waste
NOx (nitrogen oxides) emissions
SOx (sulphur oxides) emissions
NMVOC (Non Methan Volatile Organic Compounds) emissions
TSP (Total Suspended Particulate) emissions
(Million m3)
(%)
(number)
Total
1,597
1,451
128
90
20
8
3
7
18
89
58
68
(barrels)
1,036
(number)
138
(barrels)
6,222
(number)
(barrels)
(million of tonnes)
(ktonnes NO2eq)
(ktonnes SO2eq)
(ktonnes)
21
4
2.2
0.5
1.7
52.0
15.2
24.1
1.4
of which fully
consolidated
entities
1,549
1,433
114
81
16
7
3
7
2
90
54
34
422
138
6,222
21
4
1.8
0.4
1.4
30.5
4.8
13.5
0.7
Total
1,776
1,640
117
81
19
6
4
7
19
87
60
72
2,665
101
4,022
34
61
2.6
0.3
2.3
53.1
16.5
23.1
1.5
Total
1,786
1,650
119
79
20
10
4
6
16
86
59
55
3,323
102
3,236
17
63
1.4
0.7
0.7
55.6
8.4
21.5
1.5
(a) TAF: groundwater treatment facilities.
(b) The 2018 figure was updated following the closure of some investigations after the publication of the 2018 NFI. This circumstance could also occur for the 2019 data.
Number of Protected areas and KBAs in overlapping with R&M, Versalis, EniPower operational sites and UPS concessions -2019(a)
ENI Operational sites/ Concessions(c)
UNESCO World Heritage Natural Sites
Natura 2000
IUCN(d)
Ramsar(e)
Other Protected Areas
KBAs
(number)
(number)
R&M, Versalis, EniPower Operational sites
UPS Concessions
Overlapping with
operational sites
11
0
5
4
0
2
6
Adjacent to operational
sites (<1km)(b)
15
0
21
11
3
3
11
With operating
activities in the
overlapping area
31
0
15
3
2
12
13
(a) The reporting boundary, in addition to fully consolidated entities, includes also 4 UPS concessions belonging to operated companies in Egypt and 1 coastal deposit of R&M, belonging to
an operated company.
(b) The important areas for biodiversity and the operational sites do not overlap but are at distance of less than 1 km.
(c) An Eni operational site / concession may result in overlap/ adjacent to more protected areas or KBAs.
(d) Protected areas to which a IUCN (International Union for Conservation of Nature) management category is assigned.
(e) List of wetlands of international importance identified by the Countries that signed the Ramsar Convention in Iran in 1971 and which aims to ensure the sustainable development and
conservation of biodiversity in these areas.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION
123
Human rights
Eni is committed to conducting its activities with respect for human
rights and expects its Business Partners to do the same in carrying
out the assigned activities or those done in collaboration with and/
or on behalf of Eni. This commitment, based on the dignity of each
human being and on the responsibility of the Company to contribute
to the well-being of individuals and communities in the Countries
in which it operates, is set out in the Eni’s Statement on Respect
for Human Rights approved in December 2018 by the Eni Board of
Directors. The document highlights the priority areas on which this
commitment is focused and on which Eni exercises in-depth due
diligence, according to an approach developed in line with the United
Nations Guiding Principles on Business and Human Rights (UNGPs)
and pursuing continuous improvement. Eni has consolidated this
commitment in a dedicated report, Eni for Human Rights, published
for the first time in December 201931.
Human rights is one of the areas in which the Sustainability and
Scenario Committee (SSC) performs consultative and advisory
functions for the BoD. In 2019, the SSC further expanded the
activities carried out during the year and analysed the result
achieved in the third edition of the Corporate Human Rights
Benchmark (CHRB), in which Eni is among the companies that
recorded the greatest increase in their score compared to the first
edition, confirming its standing as best performer in the section
“Company Human Rights Practices.”
In 2019, Eni’s CEO confirmed the Company’s commitment to the
topic, both by signing the “CEO Guide to Human Rights” of the WBCSD
(World Business Council for Sustainable Development), which
includes a statement on the importance of the respect for human
rights and improving Eni’s business and human rights standards,
and by participating in a video interview for the WBCSD32 campaign
to launch this guide.
With regard to training, following on with the internal human
rights awareness process launched in 2016, specific e-learning
courses dedicated to the functions most involved were provided
in 2019 in order to create a common and shared language and
culture on human rights throughout the Company and to improve
the understanding of the possible impacts of the business on
human rights.
In 2019, the actions set out by the Working Group launched in 2017
in the multi-year plan identifying the main areas for improvement
and illustrating the actions necessary for the continuous progress
of performance were also completed. These actions, associated
with the 4 macro areas in which Eni’s so-called “Salient Issues”33 are
grouped together, i.e., human rights (i) in the workplace34, (ii) in the
community, (iii) in the supply chain and (iv) in security operations,
have been incorporated into specific managerial objectives directly
linked to human rights performances, assigned to all the 18 top
managers who report directly to the CEO.
Eni is committed to preventing possible negative impacts on the
human rights of individuals and host communities resulting from
the implementation of industrial projects. To this end, in 2018 Eni
adopted a risk-based model that makes use of several elements
related to the reference context, such as Verisk Maplecroft, in order
to classify upstream business projects according to potential human
rights risks and to identify appropriate management measures.
According to this approach, higher risk projects are specifically
investigated through the dedicated “Human Rights Impact
Assessment” (HRIA). In 2019, an HRIA study, with the support of
the Danish Institute for Human Rights, was carried out in Mexico on
the development project launched in Area 1 of the offshore shallow
waters of the Gulf of Mexico. In Mozambique and Angola, also in 2019
the Action Plan relating to two human rights analyses carried out in
2018 was finalised (and the related Reports issued during the year),
and two further analyses of new areas were carried out.
In 2019, an in-depth assessment was also carried out for
downstream activities, aimed at identifying the most relevant
human rights issues in Refining & Marketing processes, following
which a specific action plan was prepared.
The promotion and protection of human rights in the supply chain
is ensured through assessment activities and the application
of criteria based on international standards, such as SA 8000
standards. In 2019, 9 suppliers were assessed, of which 1 from
Ecuador, 3 from Vietnam, 1 from Mexico and 4 from Tunisia. Eni is
also committed to disseminating a code of conduct for suppliers,
which reaffirms the importance of respecting the key principles
of sustainability in the supply chain. Further actions to counter
modern forms of slavery and human trafficking and to prevent the
exploitation of minerals associated with human rights violations
in the supply chain are discussed respectively in the “Slavery
and Human Trafficking Statement”35 and in the “Eni’s position on
conflict minerals”36.
Eni manages its security operations in accordance with
international principles, including the Voluntary Principles on
Security & Human Rights. In line with its commitment, Eni has
designed a coherent set of rules and tools to ensure that: (i)
contractual terms comprise provisions on the respect for human
rights; (ii) the suppliers of security forces are selected according
to human rights criteria; (iii) security operators and supervisors
receive adequate training on the respect for human rights; and (iv)
the events considered most at risk are managed in accordance
with international standards. In addition, Eni is developing a human
rights due diligence process aimed at identifying the risk of negative
impact on human rights due to security activities and evaluating the
use of possible preventive and/or mitigation measures.
As a complement to all the actions taken to ensure respect for
human rights, since 2006 an Eni procedure has been in place,
(31) See: https://www.eni.com/assets/documents/enifor-human-rights.pdf.
(32) See: https://www.youtube.com/watch?v=xFgmRtYHn4s&feature=emb_logo
(33) The salient issues are the main issues identified at Eni on Human Rights.
(34) See the section “People” on pages 116-118.
(35) In accordance with the UK Modern Slavery Act 2015.
(36) In accordance with US SEC regulations.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2019 124
also included in the Anti-Corruption Regulatory Instruments, which
regulates the process for receiving, analysing and processing any
whistleblowing reports sent by or transmitted from stakeholders,
even confidentially or anonymously, including employees,
stakeholders, Eni’s people or third parties.
METRICS AND COMMENTS
In 2019, the Human Rights training programme continued both
with specific training modules and awareness campaigns made
available online to all employees (Security and Human Rights,
Human Rights and relations with Communities, Human Rights in
the Workplace and Human rights in the Supply Chain). In addition,
new training campaigns for the entire Eni population were launched
in 2019: “Stakeholder Sustainability, Reporting and Human Rights”
and “SDGs”.
The issue of human rights & security is also regularly addressed
in all training courses for security personnel, including the
workshops dedicated to newly appointed Security Officers, of
which a third edition was held in 2019. In 2019, the e-learning
course “Security & Human Rights” was also provided, aimed both
at new people joining the Security Function and resources who
had not yet completed the course. E-learning was delivered in
three languages (Italian, English and French) in order to increase
fruition. Thanks also to the courses mentioned above, the staff
belonging to the Security professional area trained in human
rights reached 92%.
In addition, since 2009 Eni has been conducting a training program
for public and private security forces at its subsidiaries, which was
recognized as a best practice in the 2013 joint publication Global
Compact and Principles for Responsible Investment (PRI) of the
United Nations. In 2019, the training session was held in Pakistan
and Nigeria and was addressed to the Public and Private Security
Forces, which provide their services at Eni’s management and
operational sites.
With regard to whistleblowing reports, in 2019 investigations were
completed on 74 files37, of which 2038 included human rights aspects,
mainly concerning potential impacts on workers’ rights. Among these,
26 assertions were verified with the following results: for 7 of them,
the reported facts were confirmed, at least in part, and corrective
actions were taken to mitigate and/or minimise their impact,
including: (i) actions on the Internal Control and Risk Management
System, relating to the implementation and strengthening of controls
in place, and training activities for employees; (ii) actions for
suppliers and (iii) actions against employees, including disciplinary
measures, in accordance with the 231 Model, the collective labour
agreement and other national laws applicable. At the end of the year,
15 files were still open, 8 of which referred to human rights aspects,
in particular potential impacts on workers’ rights.
Key Performance Indicators
Hours of training on human rights
In class
Distance
Employees trained on human rights(a)
Security personnel trained on human rights(b)
Security personnel (professional area) trained on human rights(c)
Security contracts containing clauses on human rights
Whistleblowing reports (assertions) on human rights violations closed during
the year(d), of which:
Founded reports (assertions)
Unfounded reports (assertions), with the adoption of corrective/improvement measures
Unfounded/Not applicable(e) (assertions)
(number)
(%)
(number)
(%)
2019
25,845
108
25,737
97
696
92
97
2018
10,653
164
10,489
91
73
96
90
2017
7,805
52
7,753
74
308
88
88
(number)
20(26)
31 (34)
29 (32)
7
8
11
9
9
16
3
9
20
(a) This percentage is calculated as the ratio between the number of registered employees who have completed a course and the total number of registered employees.
(b) The variations of the KPI Security personnel trained on human rights, in some cases also significant between one year and the next, are linked to the different characteristics of the
training projects and to the operating contingencies.
(c) This data is a percentage of a cumulated value. The change compared to 2018 (96%) is due to a change in the scope of consolidation, due to the inclusion of new resources to be trained
and the exit of resources already trained.
(d) 2017 data includes 1 report with 1 unfounded/not applicable assertion related to not fully consolidated entities.
(e) Classification introduced in 2019. They are classified as such whistleblowing/assertions in which the facts reported: (i) contain facts already covered in past specific investigations; (ii)
that do not qualify as Verifiable Detailed Reports as it is not possible to start the investigation phase; (iii) Verifiable Detailed Reports for which, in light of the outcome of preliminary checks,
it not being considered necessary to start the next investigation phase referred.
(37) Whistleblowing report: is a summary document of the investigations carried out on the report(s) (which may contain one or more detailed and verifiable assertions) providing a
summary of the investigation carried out on the reported facts, the outcome of the investigations and any action plans identified.
(38) All relating to fully consolidated entities.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION
125
Suppliers
Eni adopts qualification and selection criteria for suppliers to
assess their capacity to meet Company standards in terms of
ethical reliability, health, safety, environmental protection and
human rights. Eni meets this commitment by promoting its own
values with its suppliers and involving them in the risk prevention
process. For this purpose, as part of its procurement process, Eni:
(i) subjects all its suppliers to a qualification and due diligence
process to check their professionalism, technical capacity,
ethical, economic and financial reliability and to minimize the
inherent risks of operating with third parties; (ii) requires from
all its suppliers a formal commitment to respect the principles in
its Code of Ethics (such as protection and promotion of human
rights39, high standards of safety at work, environmental protection,
anti-corruption, compliance with laws and regulations, ethical
integrity and correctness in relations, respect for antitrust laws and
fair competition); (iii) monitors observance of this commitment,
to ensure the maintenance by Eni suppliers of the qualification
requirements over time; (iv) if criticalities emerge, requires the
implementation of improvement actions in their operating models
or, if they fail to satisfy the minimum standards of acceptability,
limits or inhibits their access to tenders.
METRICS AND COMMENTS
During 2019, about 6,000 suppliers (including all the new
ones) were subject to checks and assessment with reference
to environmental and social sustainability aspects (e.g.,
health, safety, environment, human rights, anti-corruption
and compliance). This figure is significantly higher than the
previous year as a result of the inclusion of data relating to two
additional foreign subsidiaries (Eni US and Eni Angola) and
to improvements in the reporting system, which also made
it possible to fully take into account the update of expired
qualifications. For 15% of these suppliers, potential criticalities
and/or possible areas for improvement were identified; in 89%
of cases these were not serious enough to compromise the
possibility of working with them, while for the remaining 11% of
suppliers checked, the criticalities revealed led to the temporary
suspension of relations with Eni. In 2019, critical issues and/or
areas for improvement were identified for 898 suppliers, and 96
of them received a negative score during the qualification phase
or were subject to a new preventive measure (state of attention
with clearance, suspension or revocation of qualification) or a
confirmation of the pre-existing preventive measure, issued by
Eni often as a precaution even towards suppliers not directly
contracted. The identified criticalities (resulting in the request
for the implementation of improvement plans) during the
qualification process or Human Rights assessment are related
to HSE issues or violations of Human Rights, such as health and
safety regulations, violation of the code of ethics, corruption,
environmental crimes.
Key Performance Indicators
Suppliers subjected to assessment regarding social responsibility aspects
(number)
of which: suppliers with criticalities/areas for improvement
of which: suppliers with whom Eni has terminated the relations
New suppliers that were screened using social criteria
(%)
2019
5,906
898
96
100
2018
5,184
1,008
95
100
2017
5,055
1,248
65
100
(39) A video is available on Eni’s supplier portal in which 4 Eni testimonials illustrate the main contents of the Eni Statement on Respect for Human Rights
(for more details see: https://esupplier.eni.com/PFU_en_US/formazioneeiniziative.page.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2019 126
Transparency and anti-corruption
Eni takes part in the Global Compact, which encourages member
companies to align their activities with ten universally recognized
principles in terms of human rights, labour, the environment,
transparency, and anti-corruption and to contribute to the
achievement of the SDGs. As proof of its continued commitment to
the United Nations Principles for Responsible Business, in 2019, Eni
was confirmed at the Global Compact (GC) LEAD and recognised as
one of the most active participants in this initiative on Corporate
Sustainability.
The GC principles are reflected in Eni’s Code of Ethics; in particular,
the repudiation of corruption is one of the core principles of Eni’s Code
of Ethics, which is distributed to all employees in the recruitment
phase, and of Model 231. Moreover, since 2009, Eni has designed and
developed the Anti-Corruption Compliance Program, in compliance
with the applicable provisions in force and international conventions
and taking into account guidance and best practices, as well as
the policies adopted by leading international organizations. It is an
organic system of rules and controls to prevent corrupt practices.
All Eni’s subsidiaries, in Italy and abroad, are required to adopt, by
resolution of their own Board of Directors40, both the Management
System Guideline (MSG)41 and all the other anti-corruption regulatory
instruments issued by Eni SpA.
Eni’s Anti-Corruption Compliance Program has evolved over the
years with the aim of continuous improvement; in January 2017, Eni
SpA was the first Italian company to achieve the ISO 37001:2016
“Antibribery Management Systems” certification. In order to
maintain this certification, Eni SpA is subject to annual surveillance
audits by the certifying body and the first recertification audit was
successfully completed in December 2019.
To guarantee the effectiveness of Eni’s Anti-Corruption Compliance
Program, in 2010 the anti-corruption unit was formed. It is tasked
with providing specialist support to business lines and subsidiaries
in Italy and abroad in the assessment of the reliability of at-risk
partners (so-called due diligence) and in drawing up the related
contractual controls in areas at risk of corruption. In particular,
specific anti-corruption clauses are included in contracts with
partners, which provide, inter alia, for a commitment to view and
abide by the principles contained in Eni’s Anti-Corruption MSG.
The anti-corruption unit also implements an anti-corruption training
program, both through e-learning and with classroom events,
general workshops and job specific training. The workshops offer
an overview of the anti-corruption laws applicable to Eni, the risks
that could result from their infringement for natural and legal
persons and the Anti-Corruption Compliance Program adopted to
address these risks. Generally the workshops are accompanied by
job specific training, or training for professional areas particularly
at risk in terms of corruption. In order to optimize the identification
of the recipients of the various training initiatives, a methodology
has been defined for the systematic segmentation of Eni’s people
based on the level of corruption risk according to specific risk
drivers such as Country, qualification, and professional family. The
methodology was rolled out in March 2019.
The anti-corruption unit also submits a periodic report on the
activities of the anti-corruption compliance function and quarterly
reports summarising the regulatory instruments issued during
the period to the control bodies and the Chief Financial Officer of
Eni SpA42.
In addition, in 2019, the anti-corruption unit continued the anti-
corruption training program, both online and in the classroom, for
some categories of Eni partners. The aim of this program is to raise
awareness among third parties about corruption and in particular
on how to recognise corrupt behaviour and to prevent the violation
of anti-corruption laws in their professional activity.
In order to assess the adequacy and effective operation of the
Anti-Corruption Compliance Program, as part of the integrated
audit plan approved annually by the BoD, Eni carries out specific
checks on relevant activities, with audits dedicated to analyses
of processes and companies, identified based on the riskiness
of the Country in which they operate and materiality, as well
as third parties considered to be high risk, where contractually
envisaged.
True to its commitment to better governance and greater
transparency in the extraction sector, which is crucial to foster
a proper use of resources and prevent corruption, Eni takes part
in the Extractive Industries Transparency Initiative (EITI) since
200543. In this context, Eni actively participates both at local level,
through the Multi-Stakeholder Groups in the member Countries, and
in the Board’s initiatives at international level.
Finally, Eni publishes an annual “Report on payments to
governments” from 2015 on a voluntary basis and, as of 2017,
in compliance with the reporting requirements introduced by
EU Directive 2013/34 (Accounting Directive). In addition, in
compliance with Italian Law No. 208/2015, Eni draws up the
“Country-by-Country Report” required by Action 13 of the “Base
erosion and profit shifting - BEPS” project44. Again with a view to
promoting fiscal transparency, this report is published by Eni
although there is no regulatory obligation to do so.
METRICS AND COMMENTS
During 2019, 27 audits were carried out in 20 Countries, with
anti-corruption checks that confirmed the overall adequacy and
effective operation of the Anti-Corruption Compliance Program.
In 2019, a new online training campaign on anti-corruption issues
was launched for the entire Company population. In particular,
(40) Or alternatively the equivalent body depending on the governance of the subsidiary.
(41) The MSGs are common guidelines for all Eni units for the management of operating and business support processes and cross-cutting compliance and governance processes.
(42) In 2017, a board induction was carried out for the Board of Statutory Auditors and new directors on the integrated compliance and Internal Audit processes, with a focus on whistleblowing
reports and additional checks on anti-corruption regulatory instruments.
(43) Global initiative to promote responsible and transparent use of the financial resources generated in the extraction sector.
(44) The BEPS is the action plan drawn up by the G20 and the OECD which sets out internationally transparent and shared rules on tax matters in order to combat tax base erosion and profit
shifting strategies by multinational enterprises. The plan is divided into 15 Actions of which #13 (Transfer Pricing Documentation and Country-by-Country reporting) provides for the drafting of
the Country by Country Report which collects aggregated data on turnover, profits and taxes with reference to the jurisdictions in which a company conducts business.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION 127
in 2019, 23,347 employees were trained, of whom 59% were
resources in medium/high corruption risk context.
As part of its commitment in the EITI, Eni follows its international
activities and, in the member Countries, it contributes annually
to drafting the Reports; as a member, moreover, it participates
in the activities of the Multi Stakeholder Group in Congo, Ghana,
East Timor, and the United Kingdom. In Kazakhstan, Indonesia,
Mozambique, Nigeria and Mexico, Eni’s subsidiaries interface with
EITI’s local Multi Stakeholder Groups through trade associations in
the Countries.
Key Performance Indicators
2019
2018
2017
Audit actions on risk of corruption activities(a)
(number)
of which fully
consolidated
entities
27
Total
27
E-learning for resources in medium/high corruption risk context
(number of participants)
13,886
13,564
E-learning for resources in low corruption risk context
General Workshops
Job specific training
Countries where Eni supports EITI’s local Multi Stakeholder Groups
(number)
(a) 2017 and 2018 data refer to fully consolidated entities only.
9,461
1,237
1,108
9
9,179
1,211
1,090
9
Total
32
951
1,950
1,765
1,461
8
Total
36
493
1,857
1,434
1,539
9
ALLIANCES FOR THE
PROMOTION OF LOCAL
DEVELOPMENT
In the new Company mission, Eni has charted out even more clearly
the path it has been following for several years now to address
global challenges, to contribute to the achievement of the SDGs and
to create long-term value in the Countries where it operates through
business activities that aim to increase access to energy resources
while contributing to socio-economic development. In this regard,
Eni invests in the construction of infrastructure for the production
and transport of gas for both export and domestic consumption,
recognizing that the fight against energy poverty is the first step
to meeting basic needs related to education, health and economic
diversification. These areas are part of an integrated business
cooperation model, named dual flag, that is a distinctive feature of
Eni and supports Countries in achieving their development goals.
The analysis of the local socio-economic context, which
accompanies the various business planning phases in an
increasingly in-depth manner, allows Eni to know the needs of
the people living in the areas where it operates and therefore
identify the sectors of intervention and possible solutions that are
translated into objectives in the four-year Strategic Plan. Therefore,
Eni integrates sustainability from the moment the licenses are
acquired, through the development of business projects, to
decommissioning by adopting tools and methodologies, consistent
with the main international standards, in order to ensure greater
efficiency and a systematic approach to decision-making. In this
way, business activities go hand in hand, from the very first stages
of negotiations with governments, with those supporting the basic
needs of local populations. These activities, which are set out in
specific Local Development Programmes (LDPs) in line with the
UN Agenda 2030 and with the Nationally Determined Contributions
(NDCs45), provide for five lines of action:
• Local Content: generation of added value through the transfer of
skills and know-how, activation of labour along the local supply
chain and the launch of development projects;
• Land management: optimal land management starting from
the assessment of the impacts deriving from the acquisition
of land on which Eni’s activities are carried out in order to find
possible alternatives and mitigation measures; Eni undertakes to
evaluate possible project alternatives with the aim of minimising
the consequences for local communities;
• Stakeholder engagement: enhancement of the relationship
with stakeholders based on the sharing of values, mutual
understanding and attention;
• Human Rights Impact Assessment: assessment of the impacts,
whether potential or actual, on human rights caused by Eni’s
activities, either directly or indirectly, and determination of
related prevention or mitigation measures, including through
“human rights due diligence”, in line with the guiding principles
of the United Nations Guiding Principles (UNGPs);
• Local development projects: contribution to the socio-economic
development of local communities, in accordance with national
legislation and development plans, also based on the knowledge
acquired.
(45) Presented at the Paris COP21.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2019 128
Local Development Programs (LDPs) also aim to contribute to
the improvement of access to off-grid energy and clean cooking
technologies, economic diversification (e.g., agricultural projects,
micro-credit, infrastructure interventions), education and
vocational training, forest protection and conservation and land
preservation, access to water and sanitation, and improvement of
health services for communities.
The initiatives carried out in the Countries where Eni operates
are based on an integrated approach through partnerships
which, by pooling economic, human and knowledge resources,
make it possible to maximise results. Examples of this approach
are the agreements signed with the governments of Angola,
Mexico and Mozambique, a symbol of a model that integrates
local development, renewable energy, health and hydrocarbon
exploration, as well as the partnership signed in 2019 with the
United Nations Industrial Development Organization (UNIDO) for
the improvement of youth employment, the enhancement of the
agriculture value chains, renewable energy and energy efficiency,
particularly in Africa. Collaborations like these are part of Eni’s long-
term development strategy.
In the various business design phases, in line with internationally
recognized standard principles/methodologies, Eni has developed:
- Analysis tools to better understand the reference context and
properly address local development projects (e.g., Context
analysis, Human Rights Impact Assessment - HRIA);
- Management tools to map the relationship with stakeholders
and monitor the progress of projects and the results achieved
(e.g., Stakeholder Management System - SMS, Logical Framework
Approach - LFA, Monitoring, Evaluation and Learning - MEL);
- Impact assessment tools, useful to quantify the benefits
generated by Eni in the context of business operations and
through the cooperation model (e.g., Eni Local Content Evaluation
- ELCE, Eni Impact Tool46);
- Analyses to measure the percentage spent on local suppliers
at some relevant foreign upstream subsidiaries, which in 2019
amounted to about 35%.
METRICS AND COMMENTS
In 2019, investments in local development amounted
to approximately €95.3 million47 (Eni’s share), of which
approximately 98% in the upstream sector. In Asia, approximately
€28.1 million was spent, mainly on economic diversification, in
particular for the maintenance of road infrastructure (bridges
and roads). In Africa a total of €53.3 million was spent, of which
€48.6 million was on Sub-Saharan Africa, mainly in the area of
road infrastructure maintenance and the construction of school
infrastructure. Overall, about €43.4 million was invested in
infrastructure development activities, of which €20.8 million in
Africa and €21.2 million in Asia. In the field of health, in 2019, in
order to assess the potential impact of projects on the health of
the communities involved, Eni completed 14 HIA (Health Impact
Assessment) studies, of which 9 were integrated ESHIA studies
(Environmental, Social and Health Impact Assessment). In
addition, 1 comprehensive Human Rights Impact Assessment
(HRIA) and 2 additional human rights studies were carried out
on new projects48. In 2019, 253 grievances49 were received, the
main topics being local labour, land management and energy
development and access projects.
Key Performance Indicators
Local development investment
of which: infrastructure
(€ million)
2019
2018
2017
of which fully
consolidated
entities
73.6
43.3
Total
95.3
43.4
Total
94.8
32.4
Total
70.7
22.1
(46) The ELCE (Eni Local Content Evaluation) Model was developed by Eni and validated by the Polytechnic of Milan to assess the direct, indirect and induced effects generated by
Eni’s activities at a local level in the areas in which it operates. The Eni Impact Tool is a methodology developed by Eni and validated by Polytechnic of Milan that allows assessing the
social, economic and environmental impacts of its activities at local level, quantifying the generated benefits and directing investment choices for future initiatives.
(47) The figure includes expenses for resettlement activities which in 2019 amounted to €18.6 million, of which: €18.1 million in Mozambique, €0.4 million in Ghana and €0.1 million in
Kazakhstan.
(48) See the section “Human rights” on pages 123-124 for more information.
(49) Complaints made by an individual or a group of individuals relating to actual or perceived impacts caused by the Company’s operational activities.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION
129
SUSTAINABILITY MATERIAL TOPICS
Each year, to identify non-financial content for the Strategic Plan
and sustainability report, the materiality analysis is updated. The
material aspects include the priority topics to all of Eni’s relevant
stakeholders, whether external or internal, and identify the key
challenges and opportunities of the entire cycle of activities for
creating value in the long term.
Identification of relevant aspects
The stances of relevant stakeholders are mapped both through
a dedicated platform (Stakeholder Management System - SMS),
that supports the management of local stakeholders, and through
interviews with the departments responsible for managing
relationships on an ongoing basis throughout the year. In
addition, the main ESG risks identified through the integrated
risk management model and the results of the scenario analyses
carried out by Eni were also considered in determining the relevant
aspects.
Analysis of internal and external priorities
The materiality of the topics identified is determined based on the
priority analyses:
- of the relevance of the stakeholders and their stances;
- of the main ESG risks resulting from the Integrated Risk
Management (IRM) process, which also takes into account
the evidences provided by external providers, including
RepRisk50. These risks are assessed considering also potential
environmental, social, health and safety and reputational
impacts;
- of the scenario elements - determined based on the topics
that were addressed during the Sustainability and Scenario
Committee (SSC) meetings in 2019.
The combination of these analyses, including priority topics
of all relevant stakeholders, makes it possible to take into
consideration a view that looks at the Company both from within
and without.
Sharing and validation with the governing body
The material aspects and the related analysis were presented to the
SCC and to the Board of Directors.
Below are the 2019 material topics associated with the SDGs on
which Eni’s activities have a direct or indirect impact.
2019 MATERIAL TOPICS
CARBON NEUTRALITY IN THE LONG TERM
COMBATING
CLIMATE CHANGE
GHG emissions, Promotion of natural gas,
Renewables, Biofuels and green chemistry
SDGs: 7 - 9 - 12 - 13 - 15 - 17
OPERATIONAL EXCELLENCE MODEL
PEOPLE
SAFETY
Employment, Diversity and Inclusion
Training
Occupational health and local communities health
SDGs: 3 - 4 - 5 - 8 - 10
People safety and asset integrity
SDGs: 3 - 8
REDUCTION OF ENVIRONMENTAL
IMPACTS
HUMAN RIGHTS
Water resources, biodiversity and oil spills
Rights of workers and local communities,
Supply chain and Security
SDGs: 3 - 6 - 9 - 11 - 12 - 14
15
SDGs: 1 - 4 - 8 - 10 - 16 - 17
INTEGRITY IN BUSINESS
MANAGEMENT
Transparency and Anti-Corruption
SDGs: 16 - 17
ALLIANCE FOR THE PROMOTION OF LOCAL DEVELOPMENT
ACCESS TO ENERGY
SDGs: 7 - 17
LOCAL DEVELOPMENT THROUGH
PUBLIC-PRIVATE PARTNERSHIPS
Economic diversification, Education and
Training, Access to water and hygiene,
Health
SDGs: 1 - 2 - 3 - 4 - 6 - 7
8 - 9 - 10 - 15 - 17
LOCAL CONTENT
SDGs: 4 - 8 - 9
DIGITALIZATION, TECHNOLOGICAL
INNOVATION AND RESEARCH
SDGs: 7 - 9 - 12 - 13 - 17
(50) RepRisk is a provider for the materiality analysis of ESG risks related to companies, industries, Countries and topics, whose calculation model is based on the collection and classification of
information (i.e., “risk incidents”) from media, other stakeholders and public sources external to companies.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2019 130
REPORTING PRINCIPLES AND CRITERIA
The Consolidated Disclosure of Non-Financial Information is prepared
in accordance with the Italian Legislative Decree 254/2016 and the
“Sustainability Reporting Standards”, published by the Global Reporting
Initiative (GRI Standards), according to the “core” option and was
subject to limited assurance by an independent company, auditor of
the Eni Group’s Annual Report as of December 31, 2019.
The boundary of the safety, environment, climate, whistleblowing
reports, audit actions on risk of corruption activities, anti-corruption
training and local development investment and number of Countries
where Eni, directly or indirectly, supports EITI’s local Multi Stakeholder
Groups data is in line with other corporate documents and, in some
cases, in continuity with the past. In addition to providing consistency
with the set objectives, the aim is to represent the potential impacts
of the activities managed by Eni. In these cases, comments on
performance relate to this scope. In addition to all these data,
there is an additional view only for 2019 where the data of the fully
consolidated companies are presented.
In particular, for safety, environment and climate data the boundary
is made up of companies that are significant from the point of view
of HSE impacts and includes companies under joint operation or joint
control or associates in which Eni has control of operations51. With
regard to health, the data consider the companies significant from the
point of view of health impacts and companies under joint operation or
joint control or associates in which Eni has control of operations (with
the sole exception of data relating to occupational disease reports,
which refer to fully consolidated companies only).
The boundary of data referred to anti-corruption training, local
development investments and number of Countries where Eni,
directly or indirectly, supports EITI’s local Multi Stakeholder Groups
relate to all the companies where anti-corruption training activities/
local development/support to EITI’s local Multi Stakeholder Groups
investments are envisaged.
The boundary of data referred to whistleblowing reports relate to
Eni SpA and its subsidiaries.The boundary of data referred to audit
actions on risk of corruption activities relate to: Eni SpA, subsidiaries
controlled directly and indirectly, excluding listed subsidiaries that
have their own internal audit department, associated companies,
based on specific agreements, third parties deemed to have a higher
risk, as provided for under the contracts entered with Eni. The data of
the fully consolidated companies as of December, 31 2019 are shown
for the HR indicators.
The performance indicators, selected based on the topics identified
as most significant, are collected on an annual basis according to the
consolidation boundary of the reference year and relate to the 2017-
2019 period. In general, trends in data and performance indicators are
also calculated using decimal places not shown in the document.
The data for the year 2019 are the best possible estimate with the
data available at the time of preparation of this report. In addition,
some data published in previous years may be subject to restatement
in this edition for one of the following reasons: refinement/change
in estimation or calculation methods, significant changes in the
consolidation boundary, nature of the data. If a restatement is made,
the reasons for it are appropriately disclosed in the text.
All GRI indicators in the Content Index refer to the version of the GRI
Standards published in 2016, with the exception of those in Standard
403: Occupational Health and Safety, which refer to the 2018 edition.
KPI
METHOD
CLIMATE CHANGE
GHG
EMISSIONS
EMISSION
INTENSITY
OPERATING
EFFICIENCY
ENERGY
CONSUMPTION
ENERGY
INTENSITY
Scope 1: direct GHG emissions comprise CO2, CH4 and N2O emissions; the Global Warming Potential used is 25 for CH4 and 298
for N2O. The emission factors used for the calculations are, where possible, site-specific or, alternatively, derived from available
international literature.
Scope 2: indirect GHG emissions relate to the generation of electricity, steam and heat purchased from third parties and
comprise CO2, CH4 and N2O contributions.
There are no contributions of biogenic CO2 emissions.
Numerator: direct GHG emissions (Scope 1) including CO2, CH4 and N2O.
Denominator:
• UPS: 100% operated hydrocarbon gross production
• R&M: incoming processed quantities (raw materials and semi-finished products) from own refineries
• EniPower: equivalent electrical energy produced
It expresses the GHG emissions intensity (scope 1 and scope 2 calculated on an operated basis expressed in tonCO2eq) of Eni’s
main industrial productions compared to operated production (converted by homogeneity into barrels of oil equivalent using the
Eni average conversion factors) in the individual businesses of reference, thus measuring their degree of operating efficiency in
a decarbonization scenario.
Primary sources consumption: sum of consumption of fuel gas, natural gas, refinery/process gas, LPG, light distillates/
petrol, diesel, kerosene, fuel oil, FOK and coke from FCC. Primary energy purchased from other companies: sum of purchases
of electricity, heat and steam from third parties. Consumption from renewable sources depends on the national electric mix
because consumption from photovoltaic panels installed by Eni on its assets is currently negligible.
The refining energy intensity index represents the total value of energy actually used in a given year in the various refinery processing
plants, divided by the corresponding value determined on the basis of predefined standard consumption values for each processing
plant. In order to compare the data over the years, the data for 2009 was taken as a reference (100%). For the other sectors, the index
represents the ratio between significant energy consumption associated to operated plants and the related production.
(51) In addition to fully consolidated companies, the boundary includes the following non fully consolidated companies: Agiba Petroleum Co, CARDÓN IV SA, Eni Denmark BV, Eni India Ltd, Eni Iran
BV, Eni Liverpool Bay Operating Co Ltd, Eni Portugal BV, Eni RD Congo SA, Eni Ukraine Llc, Eni Yemen Ltd, EniProgetti Egypt Ltd, Groupment Sonatrach-Agip, Karachaganak Petroleum Operating BV,
Mellitah Oil & Gas BV, Mozambique Rovuma Venture SpA, Petrobel Belayim Petroleum Co, PetroJunín SA, PetroSucre SA, United Gas Derivatives Co, Vår Energi AS, Servizi Fondo Bombole Metano
SpA, Eni USA R&M Co Inc, Esacontrol SA, Oléoduc du Rhône SA, OOO ''Eni-Nefto'', Tecnoesa SA, Costiero Gas Livorno SpA, Eni Gas Transport Services Srl, Società EniPower Ferrara Srl, Versalis Kimya
Ticaret Limited Sirketi, Versalis Pacific (India) Private Ltd, Société Energies Renouvelables Eni-ETAP SA, Industria Siciliana Acido Fosforico - ISAF - SpA (in liquidation), Oleodotto del Reno SA.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION 131
KPI
METHOD
PEOPLE, HEALTH AND SAFETY
INDUSTRIAL
RELATIONS
SENIORITY
TRAINING
HOURS
LOCAL SENIOR AND
MIDDLE MANAGERS
ABROAD
SAFETY
HEALTH
Regarding industrial relations, the minimum notice period for operational changes is in line with the provisions of the laws in
force and the trade union agreements signed in the Countries in which Eni operates.
Employees covered by collective bargaining: are those employees whose employment relationship is governed by collective
agreements or contracts, whether national, industry, company or site.
Average number of years worked by employees at Eni and its subsidiaries.
Hours delivered to Eni employees through training courses managed and carried out by Eni Corporate University (classroom
and distance) and through activities carried out by the organisational units of Eni Business areas/Companies independently,
also through on-the-job training. Average training hours are calculated as total training hours divided by the average number of
employees in the year.
Number of local senior + middle managers (employees born in the Country in which their main working activity is based) divided
by total employment abroad.
Eni uses a large number of contractors to carry out the activities within its own sites.
TRIR: total recordable injuries rate (injuries leading to days of absence, medical treatments and cases of work limitations).
Numerator: number of total recordable injuries; denominator: hours worked in the same period. Result of the ratio multiplied by
1,000,000.
High-consequence work-related injuries rate (excluding fatalities): injuries at work with days of absence exceeding 180 days or
resulting in total or permanent disability. Numerator: number of injuries at work with serious consequences; denominator: hours
worked in the same period. Result of the ratio multiplied by 1,000,000.
Near miss: an incidental event, the origin, execution and potential effect of which is accidental in nature, but which is however
different from an accident only in that the result has not proved damaging, due to luck or favourable circumstances, or to the
mitigating intervention of technical and/or organizational protection systems. Accidental events that do not turn into accidents or
injuries are therefore considered to be near misses.
The main hazards identified in 2019 at Eni were found in the following types of activities:
• load handling: events related to lifting or moving loads on the same plane;
• energized systems: events connected to equipment under pressure or containing high/low temperature fluids, exposed electrical
parts or moving mechanical parts, most often associated with accidents occurring during the use of moving mechanical parts, in
particular cutting and grinding tools.
Number of occupational disease reports filed by heirs: indicator used as a proxy for the number of deaths due to
occupational diseases.
Recordable cases of occupational diseases: number of occupational disease reports.
Main types of diseases: reports of suspected occupational disease made known to the employer concern pathologies
that may have a causal connection with the risk at work, as they may have been contracted in the course of work and
due to prolonged exposure to risk agents present in the workplace. The risk may be caused by the processing carried out,
or by the environment in which the processing takes place. The main risk agents whose prolonged exposure may lead to
an occupational disease are: (i) chemical agents (example of disease: neoplasms, respiratory system diseases, blood
diseases); (ii) biological agents (example of disease: malaria); (iii) physical agents (example of disease: hypoacusia).
ENVIRONMENT
WATER
WITHDRAWALS
Sum of sea water, freshwater, and brackish water from subsoil or surface withdrawn. TAF (groundwater treatment plant) water
represents the amount of polluted groundwater treated and reused in the production cycle.
BIODIVERSITY
Number of sites overlapping with protected areas and Key Biodiversity Areas (KBAs): R&M, Versalis and EniPower operational sites in
Italy and abroad, which are located within (or partially within) the boundaries of one or more protected areas or KBAs (as of December
2019).
Number of sites “adjacent” to protected areas or Key Biodiversity Areas (KBAs): R&M, Versalis and EniPower operational sites in Italy
and abroad which, although outside the boundaries of protected areas or KBAs, are less than 1 km away (as of December 2019).
Number of upstream concessions overlapping protected areas and Key Biodiversity Areas (KBAs), with activities in the overlapping
area: active national and international concessions, whether operated, under development or in production, present in the Company’s
databases (last updated in June 2019) that overlap one or more protected areas or KBAs, where development/production operations
(wells, sealines, pipelines and onshore and offshore installations as documented in the Company’s GIS geodatabase) are located within
the intersection area.
Number of upstream concessions overlapping protected areas and Key Biodiversity Areas (KBAs), without activities in the
overlapping area: active national and international concessions, whether operated, under development or in production, present in the
Company’s databases (last updated in June 2019) that overlap one or more protected areas or KBAs, where development/production
operations (wells, sealines, pipelines and onshore and offshore installations as documented in the Company’s GIS geodatabase) are
located outside the intersection area.
The sources used for the census of protected areas and KBAs are the “World Database on Protected Areas” and the “World Database
of Key Biodiversity Areas” (last updated in December 2019), respectively; the data was made available to Eni in the framework of
its membership in the UNEP-WCMC Proteus Partnership. There are some limitations to consider when interpreting the results of this
analysis:
• it is globally recognised that there is an overlap between the different databases of protected areas and KBAs, which may
have led to a certain degree of duplication in the analysis (some protected areas/KBAs could be counted several times);
• the databases of protected or key biodiversity areas used for the analysis, while representing the most up-to-date information
available at global level, may not be complete for each Country.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2019 132
KPI
METHOD
OIL SPILLS
WASTE
AIR PROTECTION
Spills from primary or secondary containment into the environment of oil or petroleum derivative from refining or oil waste
occurring during operation or as a result of sabotage, theft or vandalism.
Waste from production: waste from production activities, including waste from drilling activities and construction sites.
Waste from remediation activities: this includes waste from soil securing and remediation activities, demolition and
groundwater classified as waste.
The waste disposal method is communicated to Eni by the subject authorised for disposal.
NOx: total direct emissions of nitrogen oxide due to combustion processes with air. It includes emissions of NOx from flaring
activities, sulphur recovery processes, FCC regeneration, etc. It includes emissions of NO and NO2, excludes N2O.
SOx: total direct emissions of sulphur oxides, including emissions of SO2 and SO3.
NMVOC: total direct emissions of hydrocarbons, hydrocarbon substitutes and oxygenated hydrocarbons that evaporate at normal
temperature. They include LPG and exclude methane.
TSP: direct emissions of Total Suspended Particulates, finely divided solid or liquid material suspended in gaseous flows. Standard
emission factors.
HUMAN RIGHTS
SECURITY
CONTRACTS WITH
HUMAN RIGHTS
CLAUSES
WHISTLEBLOWING
REPORTS
SUPPLIERS
SUPPLIERS
SUBJECTED TO
ASSESSMENT
NEW SUPPLIERS
ASSESSED
ACCORDING TO
SOCIAL CRITERIA
The indicator “percentage of security contracts with human rights clauses” is obtained by calculating the ratio between the
“Number of security and security concierge contracts with human rights clauses” and the “Total number of security and
security concierge contracts”.
The indicator refers to the reporting files relating to Eni SpA and its subsidiaries, closed during the year and relating
to Human Rights; of the files thus identified, the number of separate claims is reported as a result of the investigation
conducted on the facts reported (founded, not founded with actions, not founded).
This indicator relates to processes managed by Eni SpA, Eni Ghana, Eni Pakistan, Eni US and Eni Angola and represents
all suppliers subjected to Due Diligence, a qualification process, HSE areas, compliance or business conduct performance
assessment, feedback process, or human rights assessment (SA8000). It relates to all suppliers for which Vendor Management
activities are centralized in Eni SpA (i.e. all Italian suppliers, mega-suppliers and international suppliers) and to local suppliers of
Eni Ghana, Eni Pakistan, Eni US and Eni Angola.
The indicator is included in that dedicated to “suppliers subjected to assessment”, as this assessment also applies to new
suppliers (in addition to those with which a relationship is already in place).
ANTI-CORRUPTION
ANTI-CORRUPTION
TRAINING
E-learning for resources in a medium/high risk context.
E-learning for resources in a low risk context.
General workshop: classroom training events for staff in a context at high risk of corruption.
Job specific training: in-class training events for professional areas at risk of corruption.
LOCAL DEVELOPMENT
LOCAL
DEVELOPMENT
INVESTMENTS
The indicator refers to Eni’s share of spending in local development projects carried out by Eni in favour of local communities
to promote the improvement of the quality of life and sustainable socio-economic development of communities in operational
contexts.
SPENDING TO
LOCAL SUPPLIERS
The indicator refers to the 2019 share of expenditure to local suppliers. “Spending to local suppliers” has been defined according
to the following alternative methods on the basis of the specific characteristics of the Countries analysed:
1) “Equity Method” (Ghana): the share of spending to local suppliers is determined on the basis of the percentage of ownership
of the corporate structure (e.g., for a JV with 60% local component, 60% of total spending to the JV is considered as spending to
local suppliers);
2) “Local Currency Method” (Angola and UK): the portion paid in local currency is identified as spending to local suppliers;
3) “Country registration method” (Iraq and Nigeria): spending to suppliers registered in the Country and not belonging to
international/megasupplier groups (e.g., drilling service/drilling support service providers) is identified as local;
4) “Country registration + Local Currency Method”:(Congo): spending to suppliers registered in the Country and not belonging
to international/megasupplier groups (e.g., drilling service/drilling support service providers) is identified as local. For the latter,
spending in local currency is considered to be local.
The Countries selected are those where a higher expenditure component was recorded compared to the Eni Group overall
expenditure.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION 133
GRI Content Index
DISCLOSURE
INDICATOR DESCRIPTION
SECTION AND/OR PAGE NUMBER
Organizational profile
102-1
102-2
102-3
102-4
102-5
102-6
102-7
102-8
102-9
102-10
102-11
102-12
102-13
Strategy
102-14
102-15
Ethics and integrity
102-16
Governance
102-18
Stakeholder engagement
102-40
102-41
102-42
102-43
102-44
Reporting practice
102-45
102-46
102-47
102-48
102-49
102-50
102-51
102-52
102-53
Name of the organization
Activities, brands, products, and services
Annual Report 2019, p. 1
Annual Report 2019, p. 3
Location of headquarters
Location of operations
Ownership and legal form
Markets served
Scale of the organization
Information on employees and other workers
Supply chain
Annual Report 2019, inside back cover
Annual Report 2019, p. 3
Annual Report 2019, inside back cover https://www.eni.com/
en_IT/company/governance/shareholders.page
Annual Report 2019, p. 3
Annual Report 2019, pp. 12-13
NFI, pp. 118; 131
NFI, pp. 118; 131
NFI, p. 125
Significant changes to the organization and its supply chain
Annual Report 2019, pp. 152-155; 295
Precautionary Principle or approach
Annual Report 2019, pp. 20-23
External initiatives
Membership of associations
Annual Report 2019, p. 15
Annual Report 2019, p. 15
Statement from senior decision-maker
Annual Report 2019, pp. 6-11
Key impacts, risks, and opportunities
Annual Report 2019, pp. 20-23; 88-104
Values, principles, standards, and norms of behavior
Annual Report 2019, pp. 2; 4-5; 29
NFI, p. 109
Governance structure
Annual Report 2019, pp. 24-29
List of stakeholder groups
Annual Report 2019, pp. 14-15
Collective bargaining agreements
NFI, pp. 118; 131
Identifying and selecting stakeholders
Approach to stakeholder engagement
Key topics and concerns raised
Annual Report 2019, pp. 14-15
Annual Report 2019, pp. 14-15
Annual Report 2019, pp. 14-15
Entities included in the consolidated financial statements
Annual Report 2019, p. 272-295
NFI, p. 130
Defining report content and topic Boundaries
List of material topics
Restatements of information
Changes in reporting
Reporting period
Date of most recent report
Reporting cycle
NFI, pp. 130; 134-135
NFI, pp. 130; 133-135
NFI, pp. 122; 130
NFI, pp. 130; 134-135
NFI, p. 130
https://www.eni.com/en-IT/publications.html
NFI, p. 130
Contact point for questions regarding the report
https://www.eni.com/en_IT/sustainability/contacts-sustainability.
page
102-54 / 102-55
Claims of reporting in accordance with the GRI Standards and
content index
102-56
External assurance
NFI, pp. 130; 133-135
NFI, p. 136-139
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2019
134
Specific Standard disclosures
Material Aspect/
GRI Disclosure
GRI DISCLOSURE DESCRIPTION
SECTION AND/ OR PAGE NUMBER
OMISSION
COMBATING CLIMATE CHANGE
GHG emissions, promotion of natural gas, renewables, biofuels and green chemistry
Economic performance - Management Approach (103-1; 103-2; 103-3)
Boundary: External and Internal
(Suppliers - RNES1, customers RNEC2)
NFI, pp. 109-111; 129; 134
201-2
Financial implications and other risks and opportunities
due to climate change
Annual Report 2019, pp.22-23; 92-95
NFI, pp. 111-115
Emissions - Management Approach (103-1; 103-2; 103-3)
Boundary: Exernal and Internal
(Suppliers - RNES1, customers RNEC2)
NFI, pp.109-110; 111-115; 129-130; 134
305-1
305-4
Direct (Scope 1) GHG emissions
GHG emissions intensity
NFI, pp. 114-115; 130
NFI, pp. 114-115; 130
Energy - Management Approach (103-1; 103-2; 103-3)
Boundary: Internal
NFI, pp. 109-110; 111-115; 129-130; 134
302-3
Energy intensity
NFI, pp. 114-115; 130
PEOPLE
Employment, diversity and inclusion, Training, Occupational health and local communities health
Market presence - Management Approach (103-1; 103-2; 103-3)
Boundary: Internal
NFI, pp. 109-110; 116-118; 129; 132; 134
202-2
Proportion of senior management hired from
the local community
NFI, pp. 117-118; 131
Employment - Management Approach (103-1; 103-2; 103-3)
Boundary: Internal
NFI, pp. 109-110; 116-118; 129; 132; 134
401-1
New employee hires and employee turnover
NFI, pp. 117-118; 131
Occupational health and safety - Management Approach (103-1; 103-2; 103-3;
403-1; 403-2; 403-3; 403-4; 403-5; 403-6; 403-7)
Boundary: Internal
NFI, pp. 109-110; 116-119; 131; 134
403-10
Work-related ill health
NFI, pp. 117-118; 131
Training and education - Management Approach (103-1; 103-2; 103-3)
Boundary: Internal
NFI, pp. 109-110; 116-118; 129; 132; 134
404-1
Average hours of training per year per employee
NFI, pp. 117-118; 131
Diversity and equal opportunity - Management Approach (103-1; 103-2; 103-3)
Boundary: Internal
NFI, pp. 109-110; 116-118; 129; 134
405-1
Diversity of governance bodies and employees
NFI, pp. 117-118
SAFETY
People safety and asset integrity
Occupational health and safety - Management Approach (103-1; 103-2;
103-3; 403-1; 403-2; 403-3; 403-4; 403-5; 403-6; 403-7)
Boundary: External and Internal (Suppliers)
NFI, pp. 109-110; 116-119; 131; 134
403-9
Work-related injuries
NFI, pp. 119; 131
REDUCTION OF ENVIRONMENTAL
Impacts Water resources, Biodiversity Oil spill
Water - Management Approach (103-1; 103-2; 103-3)
Boundary: Internal
NFI, pp. 109-110; 120-122; 129; 131-132;
134
303-1
Water withdrawal by source
NFI, pp. 121-122; 131-132
Biodiversity - Management Approach (103-1; 103-2; 103-3)
Boundary: Internal
NFI, pp. 109-110; 120-122; 129; 131-132; 134
304-1
Operational sites owned, leased, managed in, or adjacent to,
protected areas and areas of high biodiversity value outside
protected areas
NFI, pp. 121-122; 131-132
Effluents and waste - Management Approach (103-1; 103-2; 103-3)
Boundary: Internal
NFI, pp. 109-110; 120-122; 129; 131-132; 134
306-2
Waste by type and disposal method
NFI, pp. 121-122; 131-132
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION
135
Material Aspect/
GRI Disclosure
GRI DISCLOSURE DESCRIPTION
SECTION AND/ OR PAGE NUMBER
OMISSION
306-3
Significant spills
NFI, pp. 121-122; 131-132
Environmental compliance - Management Approach (103-1; 103-2; 103-3)
Boundary: Internal
NFI, pp. 109-110; 120-122; 129; 131-132;
135
307-1
Environmental compliance
Annual Report 2019, p. 214-219
HUMAN RIGHTS
Rights of workers and local communities, Supply chain, Security
Non-discrimination - Management Approach (103-1; 103-2; 103-3)
Boundary: External and Internal (Local
security forces, Suppliers - RNES1)
NFI, pp. 109-110; 123-124; 129; 135
406-1
Incidents of discrimination and corrective actions taken
NFI, pp. 123-124
Security practices - Management Approach (103-1; 103-2; 103-3)
Boundary: External and Internal (Local
security forces, Suppliers - RNES1)
NFI, pp. 109-110; 123-124; 129; 135
410-1
Security personnel trained in human rights policies
or procedures
NFI, pp. 123-124
Human rights assessment - Management Approach (103-1; 103-2; 103-3)
Boundary: External and Internal (Local
security forces, Suppliers - RNES1)
NFI, pp. 109-110; 123-124; 129; 135
412-2
Employee training on human rights policies
or procedures
NFI, pp. 123-124
Supplier social assessment - Management Approach (103-1; 103-2; 103-3)
Boundary: External and Internal (Local
security forces, Suppliers - RNES1)
NFI, pp. 109-110; 125; 129; 132; 135
414-1
New suppliers that were screened using social criteria
NFI, pp. 125; 132
INTEGRITY IN BUSINESS MANAGEMENT
Transparency and anti-corruption
Anti-corruption - Management Approach (103-1; 103-2; 103-3)
Boundary: External and Internal
(Suppliers - RNES3)
NFI, pp. 109-110; 126-129; 135
205-2
Communication and training about anti-corruption
policies and procedures
NFI, pp. 126-127; 135
ACCESS TO ENERGY, LOCAL DEVELOPMENT THROUGH PUBLIC-PRIVATE PARTNERSHIPS
Economic diversification, Education and training, Access to water and hygiene, Health
Indirect economic impacts - Management Approach (103-1; 103-2; 103-3)
Boundary: Internal
NFI, pp. 109-110; 127-129; 135
203-1
Infrastructure investments and services supported
NFI, p. 128; 132
Local communities - Management Approach (103-1; 103-2; 103-3)
Boundary: Internal
NFI, pp. 109-110; 127-129; 135
413-1
Operations with local community engagement, impact
assessments, and development programs
NFI, pp. 127-128
LOCAL CONTENT
Procurement practices - Management Approach (103-1; 103-2; 103-3)
Boundary: External and Internal
(Suppliers - RNES1)
NFI, pp. 109-110; 127-129; 135
204-1
Proportion of spending on local suppliers
NFI, pp. 127-128; 135
TECHNOLOGICAL INNOVATION
Innovation - Management Approach (103-1; 103-2; 103-3)
Boundary: Internal
NFI, pp. 109-115; 129; 135
(1) RNES: Reporting not extended to suppliers.
(2) RNEC: Reporting not extended to customers.
(3) RPES: Reporting partially extended to suppliers.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2019 136
Independent auditors’ report
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION 137
138
139
140
Other
information
Acceptance of Italian responsible payments code
Coherently with Eni’s policy on transparency and accuracy in
managing its suppliers, Eni SpA adhered to the Italian responsible
payments code established by Assolombarda in 2014. In 2019,
payments to Eni’s suppliers were made within 55 days, in line with
contractual provisions.
Article No. 15 (former Article No. 36) of Italian regulatory
exchanges (Consob Resolution No. 20249 published on
December 28, 2017). Continuing listing standards about
issuers that control subsidiaries incorporated or regulated
in accordance with laws of extra-EU Countries. Certain
provisions have been enacted to regulate continuing Italian
listing standards of issuers controlling subsidiaries that are
incorporated or regulated in accordance with laws of extra-EU
Countries, also having a material impact on the consolidated
financial statements of the parent company.
Regarding the aforementioned provisions, the Company
discloses that:
- as of December 31, 2019, nine of Eni’s subsidiaries: NAOC -
Nigerian Agip Oil Co. Ltd, Eni Petroleum Co Inc, Eni Congo SA,
Nigerian Agip Exploration Ltd, Eni Turkmenistan Ltd, Eni Canada
Holding Ltd, Eni Ghana Exploration and Production Ltd, Eni
Trading & Shipping Inc, Eni Finance USA Inc - fall within the scope
of the new continuing listing standards;
- the Company has already adopted adequate procedures to
ensure full compliance with the new regulations.
Rules for transparency and substantial and procedural fairness
of transactions with related parties
The rules for transparency and substantial and procedural fairness of
transactions with related parties adopted by the Company, in line with
the Consob listing standards are available on the Company's website
and in the Corporate Governance and Shareholding Structure Report.
Branches
In accordance with Article No. 2428 of the Italian Civil Code, it is
hereby stated that Eni has the following branches:
San Donato Milanese (MI) - Via Emilia, 1;
San Donato Milanese (MI) - Piazza Vanoni, 1.
Subsequent events
Subsequent business developments are described in the operating
review of each of Eni’s business segments.
Recent developments related to the spread of pandemic disease
COVID-19 and the trade war started by Saudi Arabia in the
international crude oil markets are described in Risk factors and
uncertainties are not reflected in the financial evaluations because
they are considered not-adjusting events.
Glossary
141
The glossary of oil and gas terms is available on Eni’s web page at the
address eni.com. Below is a selection of the most frequently used terms.
| 2nd and 3rd generation feedstock Are feedstocks not in competition
with the food supply chain as the first generation feedstock (vegetable
oils). Second generation are mostly agricultural non-food and agro/
urban waste (such as animal fats, used cooking oils and agricultural
waste) and the third generation feedstocks are non-agricultural high
innovation feedstocks (deriving from algae or waste).
| Average reserve life index Ratio between the amount of reserves at
the end of the year and total production for the year.
| Barrel/bbl Volume unit corresponding to 159 liters. A barrel of oil
corresponds to about 0.137 metric tonnes.
| Boe (Barrel of Oil Equivalent) Is used as a standard unit measure for
oil and natural gas. Effective January 1, 2019, Eni has updated the
conversion rate of gas produced to 5,408 cubic feet of gas equals 1
barrel of oil.
| Conversion Refinery process allowing the transformation of heavy
fractions into lighter fractions. Conversion processes are cracking,
visbreaking, coking, the gasification of refinery residues, etc. The
ration of overall treatment capacity of these plants and that of primary
crude fractioning plants is the conversion rate of a refinery. Flexible
refineries have higher rates and higher profitability.
| Elastomers (or Rubber) Polymers, either natural or synthetic, which,
unlike plastic, when stress is applied, return, to a certain degree, to
their original shape, once the stress ceases to be applied. The main
synthetic elastomers are polybutadiene (BR), styrene-butadiene
rubber (SBR), ethylenepropylene rubber (EPR), thermoplastic rubber
(TPR) and nitrylic rubber (NBR).
| Emissions of NOx (Nitrogen Oxides) Total direct emissions of nitrogen
oxides deriving from combustion processes in air. They include NOx
emissions from flaring activities, sulphur recovery processes, FCC
regeneration, etc. They include NO and NO2 emissions and exclude N2O
emissions.
| Emissions of SOx (Sulphur Oxides) Total direct emissions of sulfur
oxides including SO2 and SO3 emissions. Main sources are combustion
plants, diesel engines (including maritime engines), gas flaring (if the
gas contains H2S), sulphur recovery processes, FCC regeneration, etc.
| Enhanced recovery Techniques used to increase or stretch over time
the production of wells.
| Eni carbon efficiency index Ratio between 100% Scope 1 and Scope
2 GHG emissions of Eni’s main activities (on an operatorship basis)
and produced energy, converted for homogeneity into barrels of oil
equivalent.
| Green House Gases (GHG) Gases in the atmosphere, transparent
to solar radiation, that trap infrared radiation emitted by the earth's
surface. The greenhouse gases relevant within Eni's activities are
carbon dioxide (CO2), methane (CH4) and nitrous oxide (N2O).
GHG emissions are commonly reported in CO2 equivalent (CO2eq)
according to Global Warming Potential values in line with IPCC AR4, 4th
Assessment Report.
Infilling wells Infilling wells are wells drilled in a producing area in
order to improve the recovery of hydrocarbons from the field and to
maintain and/or increase production levels.
|
| LNG Liquefied Natural Gas obtained through the cooling
of natural gas to minus 160 °C at normal pressure. The gas is liquefied
to allow transportation from the place of extraction to the sites at which
it is transformed and consumed.
One ton of LNG corresponds to 1,400 cubic meters of gas.
| LPG Liquefied Petroleum Gas, a mix of light petroleum fractions, gaseous
at normal pressure and easily liquefied at room temperature through
limited compression.
| Mineral Potential (potentially recoverable hydrocarbon volumes)
Estimated recoverable volumes which cannot be defined as
reserves due to a number of reasons, such as the temporary lack of
viable markets, a possible commercial recovery dependent on the
development of new technologies, or for their location in accumulations
yet to be developed or where evaluation of known accumulations is still
at an early stage.
| Natural gas liquids Liquid or liquefied hydrocarbons recovered from
natural gas through separation equipment or natural gas treatment
plants. Propane, normal-butane and isobutane, isopentane and pentane
plus, that used to be defined natural gasoline, are natural gas liquids.
| Net-Absolute GHG Lifecycle Emissions Overall Scope 1, 2 and Scope 3
GHG emissions associated with our products and activities along their
value chain, net of carbon sinks.
| Net Carbon Footprint Overall Scope 1 and Scope 2 GHG emissions
associated with Eni’s operations, net of carbon sinks.
| Net-Carbon Intensity Ratio between the net-absolute GHG lifecycle
emissions and the energy content of products sold.
| Oil spills Discharge of oil or oil products from refining or oil waste
occurring in the normal course of operations (when accidental) or
deriving from actions intended to hinder operations of business units
or from sabotage by organized groups (when due to sabotage or
terrorism).
| Olefins (or Alkenes) Hydrocarbons that are particularly active
chemically, used for this reason as raw materials in the synthesis of
intermediate products and of polymers.
| Over/underlifting Agreements stipulated between partners regulate
the right of each to its share in the production of a set period of time.
Amounts different from the agreed ones determine temporary over/
underlifting situations.
| Plasmix The collective name for the different plastics that currently
have no use in the market of recycling and can be used as a feedstock in
the new circular economy businesses of Eni.
| Production Sharing Agreement (PSA) Contract in use in African,
Middle Eastern, Far Eastern and Latin American Countries, among
others, regulating relationships between states and oil companies
with regard to the exploration and production of hydrocarbons. The
mineral right is awarded to the national oil company jointly with the
foreign oil company that has an exclusive right to perform exploration,
development and production activities and can enter into agreements
with other local or international entities. In this type of contract, the
national oil company assigns to the international contractor the
task of performing exploration and production with the contractor’s
equipment and financial resources. Exploration risks are borne by
the contractor and production is divided into two portions: “cost oil” is
used to recover costs borne by the contractor and “profit oil” is divided
between the contractor and the national company according to
variable schemes and represents the profit deriving from exploration
and production. Further terms and conditions of these contracts may
vary from Country to Country.
142
| Proved reserves Proved oil and gas reserves are those quantities
of oil and gas, which, by analysis of geoscience and engineering
data, can be estimated with reasonable certainty to be economically
producible from a given date forward, from known reservoirs,
and under existing economic conditions. The project to extract
the hydrocarbons must have commenced or the operator must
be reasonably certain that it will commence the project within a
reasonable time.
| Reserves Quantities of oil and gas and related substances
anticipated to be economically producible, as of a given date, by
application of development projects to known accumulations. In
addition, there must exist, or there must be a reasonable expectation
that will exist, the legal right to produce or a revenue interest in
the production, installed means of delivering oil and gas or related
substances to market, and all permits and financing required to
implement the project. Reserves can be: (i) developed reserves
quantities of oil and gas anticipated to be through installed extraction
equipment and infrastructure operational at the time of the reserves
estimate; (ii) undeveloped reserves: oil and gas expected to be
recovered from new wells, facilities and operating methods.
| Scope 1 GHG Emissions Direct greenhouse gas emissions from
company’s operations, produced from sources that are owned or
controlled by the company.
| Scope 2 GHG Emissions Indirect greenhouse gas emissions
resulting from the generation of electricity, steam and heat
purchased from third parties and consumed in assets that are
owned or controlled by the company.
| Scope 3 GHG Emissions Indirect emissions associated with Eni
products along their full value chain.
| Ship-or-pay Clause included in natural gas transportation contracts
according to which the customer for which the transportation is
carried out is bound to pay for the transportation of the gas also in
case the gas is not transported.
| Take-or-pay Clause included in natural gas purchase contracts
according to which the purchaser is bound to pay the contractual
price or a fraction of such price for a minimum quantity of the gas set
in the contract also in case it is not collected by the customer. The
customer has the option of collecting the gas paid and not delivered
at a price equal to the residual fraction of the price set in the contract
in subsequent contract years.
| UN SDGs The Sustainable Development Goals (SDGs) are the
blueprint to achieve a better and more sustainable future for all
by 2030. Adopted by all United Nations Member States in 2015,
they address the global challenges the world is facing, including
those related to poverty, inequality, climate change, environmental
degradation, peace and justice.
For further detail see the website https://unsdg.un.org
| Upstream/downstream The term upstream refers to all hydrocarbon
exploration and production activities.
The term mid-downstream includes all activities inherent to oil
industry subsequent to exploration and production. Process crude
oil and oil-based feedstock for the production of fuels, lubricants
and chemicals, as well as the supply, trading and transportation
of energy commodities. It also includes the marketing business of
refined and chemical products.
| Upstream GHG Emission intensity Ratio between 100% Scope 1 GHG
emissions from upstream operated assets and 100% gross operated
production (expressed in barrel of oil equivalent).
| Wholesale sales Domestic sales of refined products to wholesalers/
distributors (mainly gasoil), public administrations and end
consumers, such as industrial plants, power stations (fuel
oil), airlines (jet fuel), transport companies, big buildings and
households. They do not include distribution through the service
station network, marine bunkering, sales to oil and petrochemical
companies, importers and international organizations.
| Work-over Intervention on a well for performing significant
maintenance and substitution of basic equipment for the collection
and transport to the surface of liquids contained in a field.
Abbreviations
/d
/y
bbbl
bbl
bboe
bcf
bcm
per day
per year
billion barrels
barrels
billion barrels of oil equivalent
billion cubic feet
billion cubic meters
bln liters
billion liters
bln tonnes
billion tonnes
boe
cm
GWh
LNG
LPG
kbbl
kboe
barrels of oil equivalent
cubic meter
gigawatthour
Liquefied Natural Gas
Liquefied Petroleum Gas
thousand barrels
thousand barrels of oil equivalent
km
ktoe
kilometers
thousand tonnes of oil equivalent
ktonnes
thousand tonnes
mmbbl
mmboe
mmcf
mmcm
million barrels
million barrels of oil equivalent
million cubic feet
million cubic meters
mmtonnes million tonnes
MTPA
Million Tonnes Per Annum
No.
NGL
PCA
ppm
PSA
Tep
TWh
number
Natural Gas Liquids
Production Concession Agreement
parts per million
Production Sharing Agreement
Ton of equivalent petroleum
Terawatt hour
GLOSSARY Consolidated financial
statements
2019
2 |
M A N A G E M E N T R E P O R T
1 4 3 |
C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S
Financial statements
Notes on consolidated financial statements
Supplemental oil and gas information
Management’s certification
Report of Independent Auditors
2 7 5 |
A N N E X
144
152
249
264
265
14 414 4
CONSOLIDATED BALANCE SHEET
January 1, 2018
Total
amount
7,363
6,219
316
14,156
4,621
191
2,768
35,634
63,158
3,012
1,283
3,474
900
1,675
4,315
182
1,141
79,140
323
115,097
2,242
2,286
15,305
472
4,317
24,622
20,179
13,124
1,022
5,937
359
1,443
42,064
87
66,773
49
4,005
36,211
4,818
1,889
(581)
(1,441)
3,374
48,275
48,324
115,097
of which
with related
parties (€ million)
ASSETS
Current assets
Cash and cash equivalents
Financial assets held for trading
73 Other current financial assets
834 Trade and other receivables
Inventories
Income tax receivables
30 Other current assets
Non-current assets
Property, plant and equipment
Right-of-use assets
Intangible assets
Inventory - Compulsory stock
Equity-accounted investments
Other investments
1,214 Other non-current financial assets
Deferred tax assets
Income tax receivables
46 Other non-current assets
Assets held for sale
TOTAL ASSETS
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
164 Short-term debt
Current portion of long-term debt
Current portion of long-term lease liabilities
2,808 Trade and other payables
Income tax payables
60 Other current liabilities
Non-current liabilities
Long-term debt
Long-term lease liabilities
Provisions
Provisions for employee benefits
Deferred tax liabilities
Income tax payables
23 Other non-current liabilities
Liabilities directly associated with assets held for sale
TOTAL LIABILITIES
SHAREHOLDERS' EQUITY
Non-controlling interest
Eni shareholders' equity
Share capital
Retained earnings
Cumulative currency translation differences
Other reserves
Treasury shares
Interim dividend
Net profit
Total Eni shareholders' equity
TOTAL SHAREHOLDERS' EQUITY
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY
December 31, 2019
December 31, 2018
Total
amount
of which
with related
parties
Total
amount
of which
with related
parties
Note
49
633
71
915
160
661
3,664
63
23
(5)
(6)
(16)
(7)
(8)
(9)
(10) (23)
(11)
(12)
(13)
(8)
(15)
(15)
(16)
(22)
(9)
(10) (23)
(24)
(18)
(18)
(12)
(17)
(9)
(10) (23)
(18)
(12)
(20)
(21)
(22)
(9)
(10) (23)
(24)
(25)
5,994
6,760
384
12,873
4,734
192
3,972
34,909
62,192
5,349
3,059
1,371
9,035
929
1,174
4,360
173
871
88,513
18
123,440
2,452
3,156
889
15,545
456
7,146
29,644
18,910
4,759
14,106
1,136
4,920
454
1,611
45,896
75,540
61
4,005
37,436
7,209
1,564
(981)
(1,542)
148
47,839
47,900
123,440
60
704
219
911
181
46
5
2,663
155
8
23
10,836
6,552
300
14,101
4,651
191
2,819
39,450
60,302
3,170
1,217
7,044
919
1,253
3,931
168
624
78,628
295
118,373
2,182
3,601
16,747
440
5,412
28,382
20,082
11,626
1,117
4,272
287
1,475
38,859
59
67,300
57
4,005
36,702
6,605
1,672
(581)
(1,513)
4,126
51,016
51,073
118,373
CONSOLIDATED FINANCIAL STATEMENTS 2019 | FINANCIAL STATEMENTS
145145
CONSOLIDATED PROFIT AND LOSS ACCOUNT
(€ million)
REVENUES AND OTHER INCOME
Sales from operations
Other income and revenues
COSTS
Purchases, services and other
Net (impairment losses) reversals of trade and other
receivables
Payroll and related costs
Other operating income (expense)
Depreciation and amortization
Net (impairment losses) reversals of tangible and intangible
assets and right-of-use assets
Write-off of tangible and intangible assets
OPERATING PROFIT
FINANCE INCOME (EXPENSE)
Finance income
Finance expense
Net finance income (expense) from financial assets held
for trading
Derivative financial instruments
INCOME (EXPENSE) FROM INVESTMENTS
Share of profit (loss) from equity-accounted investments
Other gain (loss) from investments
PROFIT BEFORE INCOME TAXES
Income taxes
Net profit
Attributable to Eni
Attributable to non-controlling interest
Earnings per share attributable to Eni (€ per share)
Basic
Diluted
2019
2018
2017
Total
amount
of which with
related parties
of which with
related parties
Total
of which with
related parties
Total
Note
(28)
69,881
1,160
71,041
1,248
4
75,822
1,116
76,938
1,383
8
66,919
4,058
70,977
1,567
41
(29) (50,874)
(9,173)
(55,622)
(8,009)
(51,548)
(9,164)
(7)
(432)
(29)
(23)
(11) (12) (13)
(2,996)
287
(8,106)
(14)
(2,188)
(11) (13)
(30)
(30)
(30)
(23) (30)
(15) (31)
(32)
(33)
(300)
6,432
3,087
(4,079)
127
(14)
(879)
(88)
281
193
5,746
(5,591)
155
148
7
155
0.04
0.04
26
(22)
319
28
(28)
19
(415)
(3,093)
129
(6,988)
(866)
(100)
9,983
96
(36)
3,967
(4,663)
115
(283)
32
(307)
(971)
(68)
1,163
1,095
10,107
(5,970)
4,137
4,126
11
4,137
1.15
1.15
(34)
331
191
(4)
(913)
(2,951)
(32)
(7,483)
225
(263)
8,012
3,924
(5,886)
(111)
837
(1,236)
(267)
335
68
6,844
(3,467)
3,377
3,374
3
3,377
0.94
0.94
CONSOLIDATED FINANCIAL STATEMENTS 2019 | FINANCIAL STATEMENTSEni Annual Report 2019
146146
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(€ million)
Net profit
Other items of comprehensive income (loss)
Items that are not reclassified to profit or loss in later periods
Remeasurements of defined benefit plans
Share of other comprehensive income (loss) on equity-accounted investments related
to benefit plans remeasurements
Change of minor investments measured at fair value with effects to other comprehensive income
Tax effect
Items that may be reclassified to profit or loss in later periods
Currency translation differences
Change in the fair value of available-for-sale financial instruments
Change in the fair value of cash flow hedging derivatives
Share of other comprehensive income (loss) on equity-accounted investments
Tax effect
Note
(25)
(25)
(25)
(25)
(25)
(25)
(25)
(25)
Total other items of comprehensive income (loss)
Total comprehensive income (loss)
Attributable to Eni
Attributable to non-controlling interest
2019
155
(42)
(7)
(3)
5
(47)
604
(679)
(6)
197
116
69
224
217
7
224
2018
4,137
2017
3,377
(15)
(33)
15
(2)
(2)
29
(4)
1,787
(5,573)
(243)
(24)
58
1,578
1,576
5,713
5,702
11
5,713
(5)
(6)
69
1
(5,514)
(5,518)
(2,141)
(2,144)
3
(2,141)
CONSOLIDATED FINANCIAL STATEMENTS 2019 | FINANCIAL STATEMENTS
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
Eni shareholders’ equity
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36,698
6,605
1,672
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(1,513)
4,126
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1,672
(581)
(1,513)
4,126
148
(37)
(7)
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(482)
(6)
(488)
(535)
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51,016
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51,012
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(37)
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(3)
(47)
604
(482)
(6)
116
217
1,513
(2,989)
(1,476)
(1,542)
(1,542)
(1,137)
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400
(400)
(400)
(29)
(4,126)
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1,564
7,209
(981)
(1,542)
148
(400)
(3,418)
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1,137
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(25)
(3)
(25)
(25)
(25)
(25)
(25)
(25)
(25)
(25)
(25)
(€ milioni)
Balance at December 31, 2018
Changes in accounting policies (IAS 28)
Balance at January 1, 2019
Net profit for the year
Other items of comprehensive income (loss)
Items that are not reclassified to profit or loss
in later periods
Remeasurements of defined benefit plans net
of tax effect
Share of other comprehensive income (loss)
on equity-accounted investments related to
benefit plans remeasurements
Change of minor investments measured at fair
value with effects to OCI
Items that may be reclassified to profit or loss
in later periods
Currency translation differences
Change in the fair value of cash flow hedge
derivatives net of tax effect
Share of “Other comprehensive income (loss)”
on equity-accounted investments
Total comprehensive income (loss) of the year
Transactions with shareholders
Dividend distribution of Eni SpA (€0.41 per share
in settlement of 2018 interim dividend of €0.42
per share)
Interim dividend distribution of Eni SpA (€0.43
per share)
Dividend distribution of other companies
Allocation of 2018 net income
Reimbursements to minority shareholders
Acquisition of treasury shares
Other changes in shareholders’ equity
Long-term share-based incentive plan
Other changes
Balance at December 31, 2019
(25)
4,005
147147
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51,069
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(37)
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(3)
(47)
604
(482)
(6)
116
224
(1,476)
(1,542)
(4)
(1)
(400)
(3,423)
9
21
30
47,900
CONSOLIDATED FINANCIAL STATEMENTS 2019 | FINANCIAL STATEMENTSEni Annual Report 2019
148148
continued CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
Eni shareholders’ equity
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4,818
1,889
(581)
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3,374
4,818
1,889
(581)
(1,441)
3,374
4,126
(17)
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48,275
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(2)
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(185)
(24)
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5,702
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1,787
(185)
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1,578
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(1,440)
(1,513)
(3)
1,441
(2,881)
(1,440)
(1,513)
(1,513)
493
493
5
(7)
(2)
36,702
(493)
(3,374)
(72)
(2,953)
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1,672
6,605
(581)
(1,513)
4,126
5
(13)
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51,016
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(13)
(8)
51,073
57
(€ million)
Balance at December 31, 2017
Changes in accounting policies (IFRS 9 and 15)
Balance at January 1, 2018
Net profit for the year
Other items of comprehensive income (loss)
Items that are not reclassified to profit or loss
in later periods
Remeasurements of defined benefit plans net
of tax effect
Change of minor investments measured at fair
value with effects to OCI
Items that may be reclassified to profit or loss
in later periods
Currency translation differences
Change in the fair value of cash flow hedge
derivatives net of tax effect
Share of “Other comprehensive income (loss)”
on equity-accounted investments
Total comprehensive income (loss) of the year
Transactions with shareholders
Dividend distribution of Eni SpA (€0.40 per
share in settlement of 2017 interim dividend of
€0.40 per share)
Interim dividend distribution of Eni SpA (€0.42
per share)
Dividend distribution of other companies
Allocation of 2017 net income
Other changes in shareholders’ equity
Long-term share-based incentive plan
Other changes
(25)
(25)
(25)
(25)
(25)
(25)
(25)
Balance at December 31, 2018
(25)
4,005
CONSOLIDATED FINANCIAL STATEMENTS 2019 | FINANCIAL STATEMENTS
segue CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
149149
Eni shareholders’ equity
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4,005
40,367
10,319
1,832
(581)
(1,441)
(1,464)
3,374
53,037
3,374
49
3
53,086
3,377
(€ million)
Balance at December 31, 2016
Net profit for the year
Other items of comprehensive income (loss)
Items that are not reclassified to profit or loss
in later periods
Remeasurements of defined benefit plans net
of tax effect
Items that may be reclassified to profit or loss
in later periods
Currency translation differences
Change in the fair value of other available-for-
sale financial instruments net of tax effect
Change in the fair value of cash flow hedge
derivatives net of tax effect
Share of “Other comprehensive income (loss)”
on equity-accounted investments
Total comprehensive income (loss) of the year
Transactions with shareholders
Dividend distribution of Eni SpA (€0.40 per share
in settlement of 2016 interim dividend of €0.40
per share)
Interim dividend distribution of Eni SpA (€0.40
per share)
Dividend distribution of other companies
Allocation of 2016 net loss
Other changes in shareholders’ equity
Other changes
Balance at December 31, 2017
4,005
(4)
(4)
2
(4)
(6)
69
61
57
(5,575)
(5,575)
(5,575)
(4)
(4)
(4)
(4)
(5,573)
(5,573)
(4)
(6)
69
(5,514)
(2,144)
3,374
1,441
(2,881)
(1,440)
(1,441)
(1,441)
(4)
(6)
69
(5,514)
(2,141)
3
(1,440)
(1,441)
(3)
(3)
(4,345)
(4,345)
(56)
(56)
35,966
74
74
4,818
4,345
1,464
(2,881)
(3)
(2,884)
1,889
(581)
(1,441)
3,374
18
18
48,030
18
18
48,079
49
CONSOLIDATED FINANCIAL STATEMENTS 2019 | FINANCIAL STATEMENTSEni Annual Report 2019
150150
CONSOLIDATED STATEMENT OF CASH FLOWS
Note
(11) (12) (13)
(14)
(11) (13)
(15) (31)
(€ million)
Net profit
Adjustments to reconcile net profit to net cash provided by operating activities
Depreciation and amortization
Net Impairments (reversals) of tangible and intangible assets
and right-of-use assets
Write-off of tangible and intangible assets
Share of (profit) loss of equity-accounted investments
Net gain on disposal of assets
Dividend income
Interest income
Interest expense
Income taxes
Other changes
Changes in working capital:
- inventories
- trade receivables
- trade payables
- provisions
- other assets and liabilities
Cash flow from changes in working capital
Net change in the provisions for employee benefits
Dividends received
Interest received
Interest paid
Income taxes paid, net of tax receivables received
Net cash provided by operating activities
- of which with related parties
Investing activities:
- tangible assets
- prepaid right-of-use assets
- intangible assets
- consolidated subsidiaries and businesses net of cash and cash equivalent
acquired
- investments
- securities held for operating purposes
- financing receivables held for operating purposes
- change in payables in relation to investing activities
Cash flow from investing activities
Disposals:
- tangible assets
- intangible assets
- consolidated subsidiaries and businesses net of cash and cash equivalent
disposed of
- tax on disposals
- investments
- securities held for operating purposes
- financing receivables held for operating purposes
- change in receivables in relation to disposals
Cash flow from disposals
Net change in securities and financing receivables held for non-operating purposes(a)
Net cash used in investing activities
- of which with related parties
(31)
(32)
(36)
(11)
(12)
(13)
(26)
(15)
(26)
(36)
2019
155
8,106
2,188
300
88
(170)
(247)
(147)
1,027
5,591
(179)
(200)
1,023
(940)
272
211
15
334
642
(238)
879
366
(23)
1,346
88
(1,029)
(5,068)
12,392
(6,356)
(8,049)
(16)
(311)
(5)
(3,003)
(8)
(229)
(307)
(11,928)
264
17
187
(3)
39
17
178
95
794
(279)
(11,413)
(2,912)
2018
4,137
6,988
866
100
68
(474)
(231)
(185)
614
5,970
(474)
1,632
109
275
87
(609)
(5,226)
13,647
(2,707)
(8,778)
(341)
(119)
(125)
(8)
(358)
408
(9,321)
1,089
5
(47)
195
15
279
606
2,142
(357)
(7,536)
(3,314)
(346)
657
284
96
749
2017
3,377
7,483
(225)
263
267
(3,446)
(205)
(283)
671
3,467
894
1,440
38
291
104
(582)
(3,437)
10,117
(2,843)
(8,490)
(191)
(510)
(585)
152
(9,624)
2,745
2
2,662
(436)
482
1
493
(434)
5,515
341
(3,768)
(3,115)
(a) From 2019, Eni’s cash flow statement is reporting in a dedicated line-item the net cash outflow (investments minus divestments) in held-for-trading financial assets and current non-operating
receivables financing, with the latter being investment of temporary cash surpluses. Those two assets are netted against financial liabilities to determine the Group net borrowings in accordance
to applicable listing standards. In previous reporting periods, cash inflows and outflows relating those assets were reported among investing activities or divesting activities relating to securities
and financing receivables, respectively. The cash flow statements of comparative periods have been reclassified accordingly.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | FINANCIAL STATEMENTS
151151
continued CONSOLIDATED STATEMENT OF CASH FLOWS
(€ million)
Increase in long-term financial debt
Repayments of long-term financial debt
Payments of lease liabilities
Increase (decrease) in short-term financial debt
Dividends paid to Eni's shareholders
Dividends paid to non-controlling interest
Reimbursements to non-controlling interest
Acquisition of additional interests in consolidated subsidiaries
Acquisition of treasury shares
Net cash used in financing activities
- of which with related parties
Effect of change in consolidation (inclusion/exclusion of significant/insignificant subsidiaries)
Effect of exchange rate changes and other changes on cash and cash equivalents
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents - beginning of the year
Cash and cash equivalents - end of the year(b)
Note
(18)
(18)
(12)
(18)
(36)
(5)
(5)
2019
1,811
(3,512)
(877)
161
(2,417)
(3,018)
(4)
(1)
(1)
(400)
(5,841)
(817)
(7)
8
(4,861)
10,855
5,994
2018
3,790
(2,757)
(713)
320
(2,954)
(3)
(2,637)
16
18
3,492
7,363
10,855
2017
1,842
(2,973)
(581)
(1,712)
(2,880)
(3)
(4,595)
(16)
7
(72)
1,689
5,674
7,363
(b) In 2018, cash and cash equivalents at the end of the year included €19 million of cash and cash equivalents of consolidated subsidiaries held for sale that were reported in the item "Assets held
for sale".
CONSOLIDATED FINANCIAL STATEMENTS 2019 | FINANCIAL STATEMENTSEni Annual Report 2019
152
NOTES ON CONSOLIDATED FINANCIAL
STATEMENTS
PRINCIPLES OF CONSOLIDATION
1 | Significant accounting policies, estimates
and judgements
BASIS OF PREPARATION
The Consolidated Financial Statements of the Eni Group have been
prepared on a going concern basis in accordance with International
Financial Reporting Standards (IFRS)1 as issued by the International
Accounting Standards Board (IASB) and adopted by the European
Union (EU) pursuant to article 6 of the EC Regulation No. 1606/2002
of the European Parliament and of the Council of July 19, 2002, and in
accordance with article 9 of the Italian Legislative Decree No. 38/05.2
The Consolidated Financial Statements have been prepared
under the historical cost convention, taking into account, where
appropriate, value adjustments, except for certain items that
under IFRSs must be measured at fair value as described in the
accounting policies that follow.
The 2019 Consolidated Financial Statements, approved by the Eni’s
Board of Directors on February 27, 2020, were audited by the external
auditor PricewaterhouseCoopers SpA. The external auditor of Eni
SpA, as the main external auditor, is wholly in charge of the auditing
activities of the Consolidated Financial Statements; when there are
other external auditors, PricewaterhouseCoopers SpA takes the
responsibility of their work.
The Consolidated Financial Statements are presented in euros and all
values are rounded to the nearest million euros (€ million), except
where otherwise indicated.
SIGNIFICANT ACCOUNTING ESTIMATES AND JUDGEMENTS
The preparation of the Consolidated Financial Statements requires the
use of estimates and assumptions that affect the assets, liabilities,
revenues and expenses recognised in the financial statements, as
well as amounts included in the notes thereto, including disclosure
of contingent assets and contingent liabilities. Estimates made
are based on complex judgements and past experience of other
assumptions deemed reasonable in consideration of the information
available at the time. The accounting policies and areas that require
the most significant judgements and estimates to be used in the
preparation of the Consolidated Financial Statements are in relation
to the accounting for oil and natural gas activities, specifically in the
determination of proved and proved developed reserves, impairment
of financial and non financial assets, leases, decommissioning and
restoration liabilities, environmental liabilities business combinations,
employee benefits, revenue from contracts with customers, fair value
measurements and income taxes. Although the Company uses its
best estimates and judgements, actual results could differ from the
estimates and assumptions used. The accounting estimates and
judgements relevant for the preparation of the Consolidated Financial
Statement are described below.
SUBSIDIARIES
The Consolidated Financial Statements comprise the financial
statements of the parent Company Eni SpA and those of its
subsidiaries, being those entities over which the Company has
control, either directly or indirectly, through exposure or rights to
their variable returns and the ability to affect those returns through
its power over the investees. To have power over an investee, the
investor must have existing rights that give it the current ability to
direct the relevant activities of the investee, i.e. the activities that
significantly affect the investee’s returns.
Subsidiaries are consolidated, on the basis of consistent
accounting policies, from the date on which control is obtained
until the date that control ceases. Assets, liabilities, income and
expenses of consolidated subsidiaries are fully recognised with
those of the parent in the Consolidated Financial Statements;
the parent’s investment in each subsidiary is eliminated against
the corresponding parent’s portion of equity of each subsidiary.
Non-controlling interests are presented separately on the balance
sheet within equity; the profit or loss attributable to non-controlling
interests is presented in a specific line item of the profit and
loss account.
For entities acting as sole-operator in the management of Oil & Gas
contracts on behalf of companies participating in a joint project, the
activities are financed proportionally based on a budget approved by
the participating companies upon presentation of periodical reports
of proceeds and expenses. Costs and revenue and other operating
data (production, reserves, etc.) of the project, as well as the related
obligations arising from the project, are recognised directly in the
financial statements of the companies involved based on their own
share. Some subsidiaries are not consolidated because they are
immaterial, either individually or in the aggregate; this exclusion
has not produced material3 effects on the Consolidated Financial
Statements4.
When the proportion of the equity held by non-controlling interests
changes, any difference between the consideration paid/received
and the amount by which the non-controlling interests are
adjusted is attributed to Eni shareholders’ equity. Conversely,
the sale of equity interests with loss of control determines the
recognition in the profit and loss account of: (i) any gain or loss
calculated as the difference between the consideration received
and the corresponding transferred net assets; (ii) any gain or loss
recognised as a result of the remeasurement of any investment
retained in the former subsidiary at its fair value; and (iii) any
amount related to the former subsidiary previously recognised
in other comprehensive income which may be reclassified
subsequently to the profit and loss account5. Any investment
retained in the former subsidiary is recognised at its fair value at the
date when control is lost and shall be accounted for in accordance
with the applicable measurement criteria.
(1) IFRSs include also International Accounting Standards (IAS), currently effective, as well as the interpretations developed by the IFRS Interpretations Committee, previously named International
Financial Reporting Interpretations Committee (IFRIC) and initially Standing Interpretations Committee (SIC).
(2) The Consolidated Financial Statements are compliant with IFRSs as issued by the IASB and effective for the year 2019.
(3) According to the requirements of the Conceptual Framework for Financial Reporting, “information is material if omitting it or misstating it could influence decisions that users make on the basis of
financial information about a specific reporting entity”.
(4) Unconsolidated subsidiaries are accounted for as described in the accounting policy for “The equity method of accounting”; for further information, see the annex “List of companies owned by Eni SpA
as of December 31, 2019”.
(5) Conversely, any amount related to the former subsidiary previously recognised in other comprehensive income, which may not be reclassified subsequently to the profit and loss account, are
reclassified in another item of equity.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
153
INTERESTS IN JOINT ARRANGEMENTS
Joint control is the contractually agreed sharing of control of an
arrangement, which exists only when decisions about the relevant
activities require the unanimous consent of the parties sharing control.
A joint venture is a joint arrangement whereby the parties that have
joint control of the arrangement have rights to the net assets of the
arrangement. Investments in joint ventures are accounted for using
the equity method as described in the accounting policy for “The
equity method of accounting”.
A joint operation is a joint arrangement whereby the parties that
have joint control of the arrangement have enforceable rights to the
assets, and enforceable obligations for the liabilities, relating to the
arrangement. In the Consolidated Financial Statements, Eni recognises
its share of the assets/liabilities and revenue/expenses of joint
operations on the basis of its rights and obligations relating to the
arrangements.
After the initial recognition, the assets/liabilities and revenue/
expenses of the joint operations are measured in accordance with
the applicable measurement criteria. Immaterial joint operations
structured through a separate vehicle are accounted for using the
equity method or, if this does not result in a misrepresentation of the
Company’s financial position and performance, at cost net of any
impairment losses.
INVESTMENTS IN ASSOCIATES
An associate is an entity over which Eni has significant influence,
that is the power to participate in the financial and operating policy
decisions of the investee, but is not control or joint control of those
policies. Investments in associates are accounted for using the
equity method as described in the accounting policy for “The equity
method of accounting”.
Consolidated companies’ financial statements are audited by external
auditors who audit also the information required for the preparation of
the Consolidated Financial Statements.
THE EQUITY METHOD OF ACCOUNTING
Investments in joint ventures, associates and immaterial
unconsolidated subsidiaries are accounted for using the equity
method6, 7.
Under the equity method, investments are initially recognised at
cost, allocating, similarly to business combinations procedures,
the purchase price of the investment to the investee’s identifiable
assets/liabilities; if this allocation is provisionally recognised at initial
recognition, it can be retrospectively adjusted within one year from the
date of initial recognition, to reflect new information obtained about
facts and circumstances that existed at the date of initial recognition.
Subsequently, the carrying amount is adjusted to reflect: (i) the
investor’s share of the profit or loss of the investee after the date of
acquisition, adjusted to account for depreciation, amortization and any
impairment losses of the equity-accounted entity’s assets based on
their fair values at the date of acquisition; and (ii) the investor’s share
of the investee’s other comprehensive income. Distributions received
from an equity-accounted investee reduce the carrying amount of the
investment. In applying the equity method, consolidation adjustments
are considered (see also the accounting policy for “Subsidiaries”).
Losses arising from the application of the equity method in excess of
the carrying amount of the investment, recognised in the profit and
loss account within “Income (Expense) from investments”, reduce
the carrying amount, net of the related expected credit losses (see
below), of any financing receivables towards the investee for which
settlement is neither planned nor likely to occur in the foreseeable
future (the so-called long-term interests), which are, in substance, an
extension of the investment in the investee. The investor’s share of
any losses of an equity-accounted investee that exceeds the carrying
amount of the investment and any long-term interests (the so-called
net investment), is recognised in a specific provision only to the
extent that the investor has incurred legal or constructive obligations
or made payments on behalf of the investee.
Whenever there is objective evidence of impairment (e.g. relevant
breaches of contracts, significant financial difficulty, probable
default of the counterparty, etc.), the net investment is tested for
impairment by comparing its carrying amount with the related
recoverable amount, determined by adopting the criteria indicated in
the accounting policy for “Impairment of non-financial assets”. When
an impairment loss no longer exists or has decreased, any reversal
of the impairment loss is recognised in the profit and loss account
within “Income (Expense) from investments”. The impairment
reversal of the net investment shall not exceed the previously
recognised impairment losses.
The sale of equity interests with loss of joint control or significant
influence over the investee determines the recognition in the
profit and loss account of: (i) any gain or loss calculated as the
difference between the consideration received and the corresponding
transferred share; (ii) any gain or loss recognised as a result of
the remeasurement of any investment retained in the former joint
venture/associate at its fair value8; and (iii) any amount related to
the former joint venture/associate previously recognised in other
comprehensive income which may be reclassified subsequently to the
profit and loss account9. Any investment retained in the former joint
venture/associate is recognised at its fair value at the date when joint
control or significant influence is lost and shall be accounted for in
accordance with the applicable measurement criteria.
BUSINESS COMBINATION
Business combinations are accounted for by applying the acquisition
method. The consideration transferred in a business combination is
the sum of the acquisition-date fair value of the assets transferred,
the liabilities incurred and the equity interests issued by the
acquirer. Acquisition-related costs are accounted for as expenses
when incurred.
(6) In the case of step acquisition of significant influence (joint control), the investment is recognised, at the acquisition date of significant influence (joint control), at the amount deriving from the use
of the equity method assuming the adoption of this method since initial acquisition; the “step-up” of the carrying amount of interests owned before the acquisition of significant influence (joint control) is
taken to equity.
(7) Joint ventures, associates and immaterial unconsolidated subsidiaries are accounted for at cost less any accumulated impairment losses, if this does not result in a misrepresentation of the Com-
pany's financial position and performance.
(8) If the retained investment continues to be accounted for using the equity method, no remeasurement at fair value is recognised in the profit and loss account.
(9) Conversely, any amount related to the former joint venture/associate previously recognised in other comprehensive income, which may not be reclassified subsequently to the profit and loss
account, are reclassified in another item of equity.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019 154
The acquirer shall measure the identifiable assets acquired and
liabilities assumed at their acquisition-date fair values10, unless
another measurement basis is required by IFRSs. The excess of the
consideration transferred over the Group’s share of the acquisition-
date fair values of the identifiable assets acquired and liabilities
assumed is recognised, on the balance sheet, as goodwill; conversely,
a gain on a bargain purchase is recognised in the profit and loss
account.
Any non-controlling interests are measured as the proportionate share
in the recognised amounts of the acquiree’s identifiable net assets
at the acquisition date excluding the portion of goodwill attributable
to them (partial goodwill method); as an alternative, non-controlling
interests may be measured at fair value, which means that goodwill
includes the portion attributable to them (full goodwill method)11. The
choice of measurement basis for goodwill (partial goodwill method vs.
full goodwill method) is made on a transaction-by-transaction basis.
In a business combination achieved in stages, the purchase price is
determined by summing the acquisition-date fair value of previously
held equity interests in the acquiree and the consideration transferred
for obtaining control; the previously held equity interests are
remeasured at their acquisition-date fair value and the resulting gain or
loss, if any, is recognised in the profit and loss account. Furthermore,
on obtaining control, any amount recognised in other comprehensive
income related to the previously held equity interests is reclassified
to the profit and loss account, or in another item of equity when such
amount may not be reclassified to the profit and loss account.
If the initial accounting for a business combination is incomplete
by the end of the reporting period in which the combination occurs,
the provisional amounts recognised at the acquisition date shall be
retrospectively adjusted within one year from the acquisition date, to
reflect new information obtained about facts and circumstances that
existed as of the acquisition date.
The acquisition of interests in a joint operation whose activity
constitutes a business is accounted for applying the principles
on business combinations accounting. In this regard, if the entity
obtains control over a business that was a joint operation, the
previously held interest in the joint operation is remeasured at
the acquisition-date fair value and the resulting gain or loss is
recognized in the profit and loss account12.
Significant accounting estimates and judgements: investments and
business combinations
The assessment of the existence of control, joint control, significant
influence over an investee, as well as for joint operations, the
assessment of the existence of enforceable rights and obligations
imply that the management makes complex judgements on the
basis of the characteristics of the investee’s structure, arrangements
between parties and other relevant facts and circumstances.
Significant accounting estimates by management are required also for
measuring the identifiable assets acquired and the liabilities assumed
in a business combination at their acquisition-date fair values. For
such measurement, to be performed also for the application of the
equity method, Eni adopts the valuation techniques generally used
by market participants taking into account the available information;
for the most significant business combinations, Eni engages external
independent evaluators.
INTRAGROUP TRANSACTIONS
All balances and transactions between consolidated companies, and
not yet realised with third parties, including unrealised profits arising
from such transactions have been eliminated.
Unrealised profits arising from transactions between the Group and its
equity-accounted entities are eliminated to the extent of the Group’s
interest in the equity-accounted entity. In both cases, unrealised
losses are not eliminated unless the transaction provides evidence of
an impairment loss of the asset transferred.
FOREIGN CURRENCY TRANSLATION
The financial statements of foreign operations having a functional
currency other than the euro, that represents the parent’s functional
currency, are translated into euros using the spot exchange rates on
the balance sheet date for assets and liabilities, historical exchange
rates for equity and average exchange rates for the profit and loss
account and the statement of cash flows (source: Reuters – WMR).
The cumulative resulting exchange differences are presented in the
separate component of Eni shareholders’ equity “Cumulative currency
translation differences” 13. Cumulative amount of exchange differences
relating to a foreign operation are reclassified to the profit and loss
account when the entity disposes the entire interest in that foreign
operation or when the partial disposal involves the loss of control,
joint control or significant influence over the foreign operation. On a
partial disposal that does not involve loss of control of a subsidiary
that includes a foreign operation, the proportionate share of the
cumulative exchange differences is reattributed to the non-controlling
interests in that foreign operation. On a partial disposal of interests
in joint arrangements or in associates that does not involve loss of
joint control or significant influence, the proportionate share of the
cumulative exchange differences is reclassified to the profit and
loss account. The repayment of share capital made by a subsidiary
having a functional currency other than the euro, without a change
in the ownership interest, implies that the proportionate share of the
cumulative amount of exchange differences relating to the subsidiary
is reclassified to the profit and loss account.
The financial statements of foreign operations which are translated
into euros are denominated in the foreign operations’ functional
currencies which generally is the US dollar.
The main foreign exchange rates used to translate the financial
statements into the parent’s functional currency are indicated below:
(10) Fair value measurement principles are described in the accounting policy for “Fair value measurements”.
(11) The choice between the partial goodwill and full goodwill method is made also for business combinations resulting in the recognition of a gain on bargain purchase in the profit and loss account.
(12) If the entity acquires additional interests in a joint operation that is a business, while retaining joint control, the previously held interest in the joint operation is not remeasured.
(13) When the foreign subsidiary is partially owned, the cumulative exchange differences, that are attributable to the non-controlling interests, are allocated to and recognised as part of “Non-controlling
interest”.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 155
(currency amount for €1)
US Dollar
Pound Sterling
Australian Dollar
Annual average
exchange rate
2019
Exchange rate
at December
31, 2019
Annual average
exchange rate
2018
Exchange rate
at December
31, 2018
Annual average
exchange rate
2017
Exchange rate
at December
31, 2017
1.12
0.88
1.61
1.12
0.85
1.60
1.18
0.88
1.58
1.15
0.89
1.62
1.13
0.88
1.47
1.20
0.89
1.53
SIGNIFICANT ACCOUNTING POLICIES
The most significant accounting policies used in the preparation of the
Consolidated Financial Statements are described below.
OIL AND NATURAL GAS EXPLORATION, APPRAISAL,
DEVELOPMENT AND PRODUCTION ACTIVITIES
Oil and natural gas exploration, appraisal and development activities
are accounted for using the principles of the successful efforts method
of accounting as described below.
ACQUISITION OF EXPLORATION RIGHTS
Costs incurred for the acquisition of exploration rights (or their
extension) are initially capitalised within the line item “Intangible assets”
as “exploration rights – unproved” pending determination of whether the
exploration and appraisal activities in the reference areas are successful
or not. Unproved exploration rights are not amortised, but reviewed to
confirm that there is no indication that the carrying amount exceeds
the recoverable amount. This review is based on the confirmation of the
commitment of the Company to continue the exploration activities and
on the analysis of facts and circumstances that indicate the absence of
uncertainties related to the recoverability of the carrying amount. If no
future activity is planned, the carrying amount of the related exploration
rights is recognised in the profit and loss account as write off. Lower
value exploration rights are pooled and amortised on a straight-line basis
over the estimated period of exploration. In the event of a discovery of
proved reserves (i.e. upon recognition of proved reserves and internal
approval for development), the carrying amount of the related
unproved exploration rights is reclassified to “proved exploration
rights”, within the line item “Intangible assets”. Upon reclassification,
or when there is any indication of impairment, the carrying amount
of exploration rights to reclassify as proved is tested for impairment
considering the higher of their value in use and their fair value less
costs of disposal. From the commencement of production, proved
exploration rights are amortised according to the unit of production
method (the so-called UOP method, described in the accounting policy
for “UOP depreciation, depletion and amortisation”).
ACQUISITION OF MINERAL INTERESTS
Costs incurred for the acquisition of mineral interests are capitalised
in connection with the assets acquired (such as exploration potential,
possible and probable reserves and proved reserves). When the
acquisition is related to a set of exploration potential and reserves,
the cost is allocated to the different assets acquired based on their
expected discounted cash flows.
Acquired exploration potential is measured in accordance with
the criteria illustrated in the accounting policy for “Acquisition of
exploration rights”. Costs associated with proved reserves are
amortised according to the UOP method (see the accounting policy
for “UOP depreciation, depletion and amortisation”). Expenditure
associated with possible and probable reserves (unproved mineral
interests) is not amortised until classified as proved reserves; in case
of a negative result, it is written off.
EXPLORATION AND APPRAISAL EXPENDITUREL
Geological and geophysical exploration costs are recognised as an
expense as incurred.
Costs directly associated with an exploration well are initially
recognised within tangible assets in progress, as “exploration and
appraisal costs – unproved” (exploration wells in progress) until the
drilling of the well is completed and can continue to be capitalised
in the following 12-month period pending the evaluation of drilling
results (suspended exploration wells). If, at the end of this period,
it is ascertained that the result is negative (no hydrocarbon found)
or that the discovery is not sufficiently significant to justify the
development, the wells are declared dry/unsuccessful and the
related costs are written off. Conversely, these costs continue to be
capitalised if and until: (i) the well has found a sufficient quantity
of reserves to justify its completion as a producing well, and (ii) the
entity is making sufficient progress assessing the reserves and the
economic and operating viability of the project; on the contrary, the
capitalised costs are recognised in the profit and loss account as write
off. Analogous recognition criteria are adopted for the costs related to
the appraisal activity. When proved reserves of oil and/or natural gas
are determined, the relevant expenditure recognised as unproved is
reclassified to proved exploration and appraisal costs within tangible
assets in progress. Upon reclassification, as well as whether there
is any indication of impairment, the carrying amount of the costs to
reclassify as proved is tested for impairment considering the higher of
their value in use and their fair value less costs of disposal. From the
commencement of production, proved exploration and appraisal costs
are depreciated according to the UOP method (see the accounting
policy for “UOP depreciation, depletion and amortisation”).
DEVELOPMENT EXPENDITURE
Development expenditure, including the costs related to unsuccessful
and damaged development wells, are capitalised as “Tangible asset
in progress – proved”. Development costs are incurred to obtain
access to proved reserves and to provide facilities for extracting,
treating, gathering and storing the Oil & Gas. They are amortised, from
the commencement of production, generally on a UOP basis. When
development projects are unfeasible/not carried on, the related costs
are written off when it is decided to abandon the project. Development
costs are tested for impairment in accordance with the criteria
described in the accounting policy for “Property, plant and equipment”.
UOP DEPRECIATION, DEPLETION AND AMORTISATION
Proved Oil & Gas assets are depreciated generally under the UOP
method, as their useful life is closely related to the availability of proved
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019
156
Oil & Gas reserves, by applying, to the depreciable amounts at
the end of each quarter a rate representing the ratio between the
volumes extracted during the quarter and the reserves existing at
the end of the quarter, increased by the volumes extracted during
the quarter. This method is applied with reference to the smallest
aggregate representing a direct correlation between expenditures
to be depreciated and Oil & Gas reserves. Proved exploration rights
and acquired proved mineral interests are amortised over proved
reserves; proved exploration and appraisal costs and development
expenditure are depreciated over proved developed reserves, while
common facilities are depreciated over total proved reserves.
PRODUCTION COSTS
Production costs are those costs incurred to operate and maintain
wells and field equipment and are recognised as an expense as
incurred.
PRODUCTION SHARING AGREEMENTS AND BUY-BACK
CONTRACTS
Oil & Gas reserves related to Production Sharing Agreements and
buy-back contracts are determined on the basis of contractual terms
related to the recovery of the contractor’s costs to undertake and
finance exploration, development and production activities at its own
risk (Cost Oil) and the Company’s stipulated share of the production
remaining after such cost recovery (Profit Oil). Revenues from the
sale of the lifted production, against both Cost Oil and Profit Oil, are
accounted for on an accrual basis, whilst exploration, development
and production costs are accounted for according to the above-
mentioned accounting policies. The Company’s share of production
volumes and reserves includes the share of hydrocarbons that
corresponds to the taxes to be paid, according to the contractual
agreement, by the national government on behalf of the Company.
As a consequence, the Company has to recognise at the same time
an increase in the taxable profit, through the increase of the revenue,
and a tax expense.
PLUGGING AND ABANDONMENT OF WELLS
Costs expected to be incurred with respect to the plugging and
abandonment of a well, dismantlement and removal of production
facilities, as well as site restoration, are capitalised, consistent
with the accounting policy described under “Property, plant and
equipment”, and then depreciated on a UOP basis.
Significant accounting estimates and judgements: oil and natural
gas activities
Engineering estimates of the Company’s Oil & Gas reserves are
inherently uncertain. Proved reserves are the estimated volumes of
crude oil, natural gas and gas condensates, liquids and associated
substances which geological and engineering data demonstrate
that can be economically producible with reasonable certainty from
known reservoirs under existing economic conditions and operating
methods. Although there are authoritative guidelines regarding
the engineering and geological criteria that must be met before
estimated Oil & Gas reserves can be categorised as “proved”, the
accuracy of reserve estimates depends on a number of factors,
assumptions and variables, including: (i) the quality of available
geological, technical and economic data and their interpretation
and judgement; (ii) projections regarding future rates of production
and operating costs as well as the timing and amount of development
expenditures; (iii) changes in the prevailing tax rules, other government
regulations and contractual conditions; (iv) results of drilling, testing
and the actual production performance of Eni’s reservoirs after the date
of the estimates which may drive substantial upward or downward
revisions; and (v) changes in oil and natural gas prices which could
affect expected future cash flows and the quantities of Eni’s proved
reserves since the estimates of reserves are based on prices and costs
existing as of the date when these estimates are made. Lower oil prices
or the projections of higher operating and development costs may impair
the ability of the Company to economically produce reserves leading to
downward reserve revisions.
Many of the factors, assumptions and variables involved in
estimating proved reserves are subject to change over time and
therefore affect the estimates of oil and natural gas reserves.
The determination of whether potentially economic oil and natural
gas reserves have been discovered by an exploration well is
made within a year after well completion. The evaluation process
of a discovery, which requires performing additional appraisal
activities on the potential oil and natural gas field and establishing
the optimum development plans, can take longer, in most cases,
depending on the complexity of the project and on the size of capital
expenditures required. During this period, the costs related to these
exploration wells remain suspended on the balance sheet. In any
case, all such capitalised costs are reviewed, at least, on an annual
basis to confirm the continued intent to develop, or otherwise to
extract value from the discovery.
Field reserves will be categorised as proved only when all the criteria
for attribution of proved status have been met. Initially, all booked
reserves are classified as proved undeveloped. Subsequently,
volumes are reclassified from proved undeveloped to proved
developed as a consequence of development activity. Generally,
reserves are booked as proved developed when the first oil or gas
is produced. Major development projects typically take one to four
years from the time of initial booking to the start of production.
Estimated proved reserves are used in determining depreciation,
amortisation and depletion charges and impairment charges.
Assuming all other variables are held constant, an increase in
estimated proved developed reserves for each field decreases
depreciation, amortisation and depletion charge under the UOP
method. Conversely, a decrease in estimated proved developed
reserves increases depreciation, amortisation and depletion charge.
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment, including investment properties,
are recognised using the cost model and stated at their purchase
price or construction cost including any costs directly attributable
to bringing the asset to the location and condition necessary for it
to be capable of operating in the manner intended by management.
For assets that necessarily take a substantial period of time to get
ready for their intended use, the purchase price or construction cost
comprises the borrowing costs incurred in the period to get the asset
ready for use that would have been avoided if the expenditure had
not been made.
In the case of a present obligation for dismantling and removal
of assets and restoration of sites, the initial carrying amount of
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 157
an item of property, plant and equipment includes the estimated
(discounted) costs to be incurred when the removal event occurs; a
corresponding amount is recognised as part of a specific provision
(see the accounting policy for “Decommissioning and restoration
liabilities”).
Property, plant and equipment are not revalued for financial
reporting purposes.
Expenditures on upgrading, revamping and reconversion are
recognised as items of property, plant and equipment when it is
probable that they will increase the expected future economic
benefits of the asset. Assets acquired for safety or environmental
reasons, although not directly increasing the future economic
benefits of any particular existing item of property, plant and
equipment, qualify for recognition as assets when they are
necessary for running the business.
Depreciation of tangible assets begins when they are available
for use, i.e. when they are in the location and condition necessary
for it to be capable of operating as planned. Property, plant and
equipment are depreciated on a systematic basis over their useful
life. The useful life is the period over which an asset is expected
to be available for use by the Company. When tangible assets are
composed of more than one significant part with different useful
lives, each part is depreciated separately. The depreciable amount is
the asset’s carrying amount less its residual value at the end of its
useful life, if it is significant and can be reasonably determined. Land
is not depreciated, even when acquired together with a building.
Tangible assets held for sale are not depreciated (see the accounting
policy for “Assets held for sale and discontinued operations”).
Changes in the asset's useful life, in its residual value or in the
pattern of consumption of the future economic benefits embodied in
the asset, are accounted for prospectively.
Assets to be handed over for no consideration are depreciated over
the shorter term between the duration of the concession or the
asset’s useful life.
Replacement costs of identifiable parts in complex assets are
capitalised and depreciated over their useful life; the residual
carrying amount of the part that has been substituted is charged to
the profit and loss account. Non-removable leasehold improvements
are depreciated over the earlier of the useful life of the improvements
and the lease term. Expenditures for ordinary maintenance and
repairs are recognised as an expense as incurred.
The carrying amount of property, plant and equipment is
derecognised on disposal or when no future economic benefits
are expected from its use or disposal; the arising gain or loss is
recognised in the profit and loss account.
LEASES14, 15
A contract is, or contains, a lease, if the contract conveys the right to
control the use of an identified asset for a period of time in exchange for
consideration16; such right exists whether, throughout the period of use,
the customer has both the right to obtain substantially all of the economic
benefits from use of the identified asset and the right to direct the use of
the identified asset.
At the commencement date of the lease (i.e. the date on which the
underlying asset is available for use), a lessee recognises on the balance
sheet an asset representing its right to use the underlying leased asset
(hereinafter also referred as right-of-use asset) and a liability representing
its obligation to make lease payments during the lease term (hereinafter
also referred as lease liability17). The lease term is the non-cancellable
period of a contract, together with, if reasonably certain, periods covered
by extension options or by the non-exercise of termination options.
In particular, the lease liability is initially recognised at the present value
of the following lease payments18 that are not paid at the commencement
date: (i) fixed payments (including in-substance fixed payments), less
any lease incentives receivable; (ii) variable lease payments that depend
on an index or a rate19; (iii) amounts expected to be payable by the lessee
under residual value guarantees; (iv) the exercise price of a purchase
option if the lessee is reasonably certain to exercise that option; and (v)
payments of penalties for terminating the lease, if the lease term reflects
the lessee exercising an option to terminate the lease. The lease payments
are discounted using the interest rate implicit in the lease or, if that rate
cannot be readily determined, the lessee’s incremental borrowing rate. The
latter is determined considering the term of the lease, the frequency and
currency of the contractual lease payments, as well as the features of the
lessee’s economic environment (reflected in the country risk premium
assigned to each Country where Eni operates).
After the initial recognition, the lease liability is measured on an amortised
cost basis and is remeasured, normally, as an adjustment to the
carrying amount of the related right-of-use asset, to reflect changes to
the lease payments due, essentially, to: (i) modifications in the lease
contract not accounted as a separate lease; (ii) changes in indexes or
rates (used to determine the variable lease payments); or (iii) changes
in the assessment of contractual options (e.g. options to purchase the
underlying asset, extension or termination options).
The right-of-use asset is initially measured at cost, which comprises: (i)
the amount of the initial measurement of the lease liability; (ii) any initial
direct costs incurred by the lessee20; (iii) any lease payments made at or
before the commencement date, less any lease incentives received; and
(iv) an estimate of costs to be incurred by the lessee in dismantling and
(14) The accounting policies related to leases have been defined on the basis of IFRS 16 “Leases” effective from January 1, 2019. As allowed by the accounting standard, the new requirements
have been applied without restating the comparative years. The previous accounting policies about leases required essentially that: (i) assets held under finance lease, or under arrangements
that did not take the legal form of a finance lease but substantially transferred all the risks and rewards incidental to ownership of the leased asset, were recognised, at the commencement of
the lease, at their fair value, net of grants attributable to the lessee or, if lower, at the present value of the minimum lease payments, within property, plant and equipment as a contra account to
a financing payable to the lessor; and (ii) lease payments under an operating lease were recognised as an expense over the lease term.
(15) As expressly provided for in IFRS 16, this accounting policy does not apply to leases to explore for and extract resources such as those for Oil & Gas rights, leases of land and any rights of
way related to Oil & Gas activities.
(16) The assessment of whether the contract is, or contains, a lease is performed at the inception date, that is the earlier of the date of a lease agreement and the date of commitment by the
parties to the principal terms and conditions of the lease.
(17) Eni applies the recognition exemptions allowed for short-term leases (for certain classes of underlying assets) and low-value leases, by recognising the lease payments associated with
those leases as an expense on a straight-line basis over the lease term.
(18) Eni, in accordance with the practical expedient allowed by the accounting standard, does not separate non-lease components from lease components except for main contracts related to
upstream activities (drilling rigs), which provide for single payments relating to both lease and non-lease components.
(19) Conversely, the other kinds of variable lease payments (e.g. payments that depend on the use of an underlying leased asset) are not included in the carrying amount of the lease liability,
but are recognised in the profit and loss account as operating expenses over the lease term.
(20) Initial direct costs are incremental costs of obtaining a lease that would not have been incurred if the lease had not been obtained.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019 158
removing the underlying asset, restoring the site on which it is located
or restoring the underlying asset to the condition required by the terms
and conditions of the lease. After the initial recognition, the right-of-use
asset is adjusted for any accumulated depreciation21, any accumulated
impairment losses (see the accounting policy for “Impairment of non-
financial assets”) and any remeasurement of the lease liability.
In the Oil & Gas activities, the operator of an unincorporated joint
operation which enters into a lease contract as the sole signatory
recognises on the balance sheet: (i) the entire lease liability if,
based on the contractual provisions and any other relevant facts and
circumstances, it has primary responsibility for the liability towards
the third-party supplier; and (ii) the entire right-of-use asset, unless,
on the basis of the terms and conditions of the contract, there is a
sublease with the followers.
The followers’ share of the right-of-use asset, recognised by
the operator, will be recovered according to the joint operation’s
contractual arrangements by billing the project costs attributable to
the followers and collecting the related cash calls. Costs recovered
from the followers are recognised as “Other income and revenues”
in the profit and loss account and as net cash provided by operating
activities in the statement of cash flows.
Differently, if a lease contract is signed by all the partners, Eni
recognises its share of the right-of-use asset and lease liability on
the balance sheet based on its working interest.
If Eni does not have primary responsibility for the lease liability, it
does not recognise any right-of-use asset and lease liability related
to the lease contract.
When lease contracts are entered into by companies other than
subsidiaries that act as operators on behalf of the other participating
companies (the so-called operating companies), consistent with
the provision to recover from the followers the costs related to the
Oil & Gas activities, the participating companies recognise their
share of the right-of-use assets and the lease liabilities based on
their working interest, defined according to the expected use, to the
extent that it is reliably determinable, of the underlying assets.
Significant accounting estimates and judgements: lease transactions
With reference to lease contracts, management made significant
estimates and judgements related to: (i) determining the lease
term, making assumptions about the exercise of extension and/
or termination options; (ii) determining the lessee’s incremental
borrowing rate; (iii) identifying and, where appropriate, separating
non-lease components from lease components, where an
observable stand-alone price is not readily available, taking into
account also the analysis performed with external experts; (iv)
recognising lease contracts, for which the underlying assets
are used in Oil & Gas activities (mainly drilling rigs and FPSOs),
entered into as operator within an unincorporated joint operation,
considering if the operator has primary responsibility for the
liability towards the third-party supplier and the relationships
with the followers; (v) identifying the variable lease payments
and the related characteristics in order to include them in the
measurement of the lease liability.
INTANGIBLE ASSETS
Intangible assets are identifiable non-monetary assets without
physical substance, controlled by the Company and able to produce
future economic benefits, and goodwill. An asset is classified as
intangible when management is able to distinguish it clearly from
goodwill. This condition is normally met when: (i) the intangible
asset arises from contractual or other legal rights, or (ii) the asset is
separable, i.e. can be sold, transferred, licensed, rented or exchanged,
either individually or together with other assets. An entity controls
an intangible asset if it has the power to obtain the future economic
benefits flowing from the underlying asset and to restrict the access of
others to those benefits.
Intangible assets are initially recognised at cost as determined by the
criteria used for tangible assets and they are not revalued for financial
reporting purposes.
Intangible assets with finite useful lives are amortised on a systematic
basis over their useful life; the amount to be amortised and the
recoverability of the carrying amount are determined in accordance
with the criteria described in the accounting policy for “Property, plant
and equipment”.
Goodwill and intangible assets with indefinite useful lives are not
amortised. For the recoverability of the carrying amounts of the
goodwill and other intangible assets see the accounting policy
“Impairment of non-financial assets”.
Costs of obtaining a contract with a customer are recognised on the
balance sheet if the Company expects to recover those costs. The
intangible asset arising from those costs is amortised on a systematic
basis, that is consistent with the transfer to the customer of the goods
or services to which the asset relates, and is tested for impairment22.
Costs of technological development activities are capitalised when:
(i) the cost attributable to the development activity can be measured
reliably; (ii) there is the intention and the availability of financial and
technical resources to make the asset available for use or sale; and
(iii) it can be demonstrated that the asset is able to generate probable
future economic benefits.
The carrying amount of intangible assets is derecognised on disposal
or when no future economic benefits are expected from its use or
disposal; any resulting gain or loss is recognised in the profit and loss
account.
IMPAIRMENT OF NON-FINANCIAL ASSETS
Non-financial assets (tangible assets, intangible assets and right-of-
use assets) are tested for impairment whenever events or changes
in circumstances indicate that the carrying amounts for those assets
may not be recoverable.
The recoverability assessment is performed for each cash-
generating unit (hereinafter also CGU) represented by the smallest
identifiable group of assets that generate cash inflows that are
largely independent of the cash inflows from other assets or group of
assets. CGUs are identified considering, inter alia, how management
(21) Depreciation charges are recognised on a systematic basis from the commencement date to the earlier of the end of the useful life of the right-of-use asset or the end of the lease term. Nevertheless,
if the lease transfers ownership of the underlying asset to the lessee by the end of the lease term, or if the cost of the right-of-use asset reflects that the lessee will exercise a purchase option, the right-of-
use asset is depreciated from the commencement date to the end of the useful life of the underlying asset.
(22) The accounting policies adopted until 2017 (before applying IFRS 15) required the capitalisation of directly attributable customer acquisition costs when all the following conditions were met: (i) the
capitalised costs can be measured reliably; (ii) there is a contract binding the customer for a specified period of time; and (iii) it is probable that the costs will be recovered through the revenue from the
sales, or, where the customer withdraws from the contract in advance, through the collection of a penalty.
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159
monitors the entity’s operations (such as by business lines) or how
management makes decisions about continuing or disposing of the
entity’s assets and operations.
Cash-generating units may include corporate assets which do not
generate cash inflows independently of other assets or group of
assets, allocable on a reasonable and consistent basis. Corporate
assets not attributable to a single cash-generating unit are allocated
to a group of cash-generating units. Goodwill is tested for impairment
at least annually, and whenever there is any indication of impairment,
at the lowest level within the entity at which it is monitored for internal
management purposes. Right-of-use assets, which generally do not
generate cash inflows independently of other assets or groups of
assets, are allocated to the CGU to which they belong; the right-of-use
assets which cannot be fully attributed to a CGU are considered as
corporate assets.
The recoverability of a CGU is assessed by comparing its carrying
amount with the recoverable amount, which is the higher of the CGU’s
fair value less costs of disposal and its value in use. Value in use is
the present value of the future cash flows expected to be derived from
continuing use of the CGU and, if significant and reliably measurable,
the cash flows expected to be obtained from its disposal at the end
of its useful life, after deducting the costs of disposal. The expected
cash flows are determined on the basis of reasonable and supportable
assumptions that represent management’s best estimate of the range
of economic conditions that will exist over the remaining useful life of
the cash-generating unit, giving greater weight to external evidence.
The value in use of CGUs which include material right-of-use assets
is calculated, normally, by ignoring lease payments included in the
measurement of the lease liabilities.
With reference to commodity prices, management uses the price
scenario adopted for economic and financial projections and for the
evaluation of the investments over their entire life. In particular, for
the cash flows associated with oil, natural gas and petroleum products
prices (and prices derived from them), the price scenario is approved
by the Board of Directors and is based on management’s planning
assumptions, in the short and medium term, takes into account
the projections of market analysts and, if there is a sufficient
liquidity and reliability level, on the forward prices prevailing in the
marketplace.
For impairment test purposes, cash outflows expected to be incurred
to guarantee compliance with laws and regulations regarding CO2
emissions (e.g. Emission Trading Scheme) or on a voluntary basis
(e.g. cash outflows related to forestry certificates acquired or
produced consistent with the Company's decarbonization strategy
– hereinafter also forestry) are taken into account. In particular,
in estimating value in use, the cash outflows for forestry projects23
are included, consistent with the medium term target of the
decarbonization strategy, within the expected cash outflows of the
segment whose emissions are offset. Currently, considering that
the forestry projects can be developed in Countries where Eni does
not carry out operating activities and considering the difficulty to
allocate such cash outflows, on a reasonable and consistent basis,
to the CGUs of the segment, the related discounted cash outflows are
treated as a reduction of the headroom of that segment.
For the determination of value in use, the estimated future cash
flows are discounted using a rate that reflects a current market
assessment of the time value of money and of the risks specific to
the asset that are not reflected in the estimated future cash flows.
In particular, the discount rate used is the Weighted Average Cost
of Capital (WACC) adjusted for the specific country risk of the CGU.
These adjustments are measured considering information from
external parties. WACC differs considering the risk associated with
each operating segment/business where the asset operates. In
particular, for the assets belonging to the Gas & Power segment
and the Chemical business, taking into account their different risk
compared to Eni as a whole, specific WACC rates have been defined
on the basis of a sample of comparable companies, adjusted to
take into account the specific country-risk premium. For the other
segments/businesses, a single WACC is used considering that the
risk is the same to that of Eni as a whole. Value in use is calculated
net of the tax effect as this method results in values similar to
those resulting from discounting pre-tax cash flows at a pre-tax
discount rate derived, through an iteration process, from a post-tax
valuation.
When the carrying amount of the CGU, including goodwill allocated
thereto, determined taking into account any impairment loss of the
non-current assets belonging to the CGU, exceeds its recoverable
amount, the excess is recognised as an impairment loss. The
impairment loss is allocated first to reduce the carrying amount of
goodwill; any remaining excess is allocated to the other assets of the
unit pro-rata on the basis of the carrying amount of each asset in the
CGU, up to the recoverable amount of assets with finite useful lives.
When an impairment loss no longer exists or has decreased, a
reversal of the impairment loss is recognised in the profit and loss
account. The impairment reversal shall not exceed the carrying
amount that would have been determined, net of depreciation, had
no impairment loss been recognised for the asset in prior years.
An impairment loss recognised for goodwill is not reversed in a
subsequent period24.
GRANTS RELATED TO ASSETS
Government grants related to assets are recognised by deducting
them in calculating the carrying amount of the related assets when
there is reasonable assurance that the Company will comply with the
conditions attaching to them and the grants will be received.
INVENTORIES
Inventories, including compulsory stock, are measured at the lower of
purchase or production cost and net realisable value. Net realisable value
is the estimated selling price in the ordinary course of business less the
estimated costs of completion and the estimated costs necessary to
make the sale, or, with reference to inventories of crude oil and petroleum
products already included in binding sale contracts, the contractual selling
price. Inventories which are principally acquired with the purpose of
(23) For the recognition criteria of forestry certificates see the accounting policy for “Costs”.
(24) Impairment losses recognised for goodwill in an interim period are not reversed also when, considering conditions existing in a subsequent interim period, they would have been recognised in a
smaller amount or would not have been recognised.
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160
selling in the near future and generating a profit from fluctuations in price
are measured at fair value less costs to sell. Materials and other supplies
held for use in production are not written down below cost if the finished
products in which they will be incorporated are expected to be sold at or
above cost.
The cost of inventories of hydrocarbons (crude oil, condensates and
natural gas) and petroleum products is determined by applying the
weighted average cost method on a three-month basis, or on a different
time period (e.g. monthly), when it is justified by the use and the turnover
of inventories of crude oil and petroleum products; the cost of inventories
of the Chemical business is determined by applying the weighted average
cost on an annual basis.
When take-or-pay clauses are included in long-term gas purchase
contracts, pre-paid gas volumes that are not withdrawn to fulfill minimum
annual take obligations are measured using the pricing formulas
contractually defined. They are recognised under “Other assets” as
“Deferred costs” as a contra to “Other payables” or, after settlement, to
“Cash and cash equivalents”. The allocated deferred costs are charged to
the profit and loss account: (i) when natural gas is actually withdrawn –
the related cost is included in the determination of the weighted average
cost of inventories; and (ii) for the portion which is not recoverable, when
it is not possible to withdraw the previously pre-paid gas, within the
contractually defined deadlines. Furthermore, the allocated deferred costs
are tested for economic recoverability by comparing the related carrying
amount and their net realisable value, determined adopting the same
criteria described for inventories.
Significant accounting estimates and judgements: impairment of
non-financial assets
The recoverability of non-financial assets is assessesed whenever events
or changes in circumstances indicate that carrying amounts of the
assets are not recoverable. Such impairment indicators include changes
in the Group’s business plans, changes in commodity prices leading to
unprofitable performance, a reduced capacity utilisation of plants and, for
Oil & Gas properties, significant downward revisions of estimated proved
reserve quantities or significant increase of the estimated development
and production costs. Determination as to whether and how much an
asset is impaired involves management estimates on highly uncertain
and complex matters such as future commodity prices, future discount
rates, future development expenditure and production costs, the effects of
inflation and technology improvements on operating expenses, production
profiles and the outlook for global or regional market supply-and-demand
conditions also with reference to the decarbonization process and the
effects of changes in regulatory requirements. Similar remarks are
valid for assessing the physical recoverability of assets recognised on
the balance sheet (deferred costs – see also the accounting policy for
“Inventories”) related to natural gas volumes not withdrawn under long-
term supply contracts with take-or-pay clauses.
The expected future cash flows used for impairment analyses are based
on judgemental assessments of future production volumes, prices and
costs, considering available information at the date of review and are
discounted by using a rate which considers the risks specific to the asset.
For oil and natural gas properties, the expected future cash flows are
estimated principally based on developed and undeveloped proved
reserves including, among other elements, production taxes and the
costs to be incurred for the reserves yet to be developed. The estimate
of the future amount of production is based on assumptions related to
future commodity prices, lifting and development costs, field decline
rates, market demand and other factors. The cash flows associated to
Oil & Gas commodities are estimated on the basis of forward market
information, if there is a sufficient liquidity and reliability level, on the
consensus of independent specialised analysts and on management’s
forecasts about the evolution of the supply and demand fundamentals.
FINANCIAL INSTRUMENTS25
FINANCIAL ASSETS
Financial assets are classified, on the basis of both contractual cash
flow characteristics and the entity’s business model for managing
them, in the following categories: (i) financial assets measured at
amortised cost; (ii) financial assets measured at fair value through
other comprehensive income (hereinafter also OCI); (iii) financial
assets measured at fair value through profit or loss.
At initial recognition, a financial asset is measured at its fair value
plus, in the case of a financial asset not at fair value through
profit or loss, transaction costs that are directly attributable; at
initial recognition, trade receivables that do not have a significant
financing component are measured at their transaction price.
After initial recognition, financial assets whose contractual terms
give rise to cash flows that are solely payments of principal and
interest on the principal amount outstanding are measured at
amortised cost if they are held within a business model whose
objective is to hold financial assets in order to collect contractual
cash flows (the so-called hold to collect business model). For
financial assets measured at amortised cost, interest income
determined using the effective interest rate, foreign exchange
differences and any impairment losses26 (see the accounting policy
for “Impairment of financial assets”) are recognised in the profit and
loss account.
Conversely, financial assets that are debt instruments are measured
at fair value through OCI (hereinafter also FVTOCI) if they are held
within a business model whose objective is achieved by both
collecting contractual cash flows and selling financial assets
(the so-called hold to collect and sell business model). In these
cases: (i) interest income determined using the effective interest
rate, foreign exchange differences and any impairment losses
(see the accounting policy for “Impairment of financial assets”)
are recognised in the profit and loss account; (ii) changes in fair
value of the instruments are recognised in equity, within other
comprehensive income. The accumulated changes in fair value,
recognised in the equity reserve related to other comprehensive
(25) The accounting policies related to financial instruments were defined on the basis of IFRS 9 “Financial Instruments” effective from 2018; as required by the accounting standard, the new
requirements have been applied starting from January 1, 2018 without restating the comparative information. With reference to the financial instruments held by the Company, the previous accounting
policies (applied until 2017) required essentially: (i) the classification of financial assets on the basis of the categories under IAS 39; (ii) recognition and measurement of impairment losses if there was
objective evidence that an impairment loss had been incurred (the so-called incurred loss model); and (iii) more stringent hedge accounting requirements (mainly referred to the assessment of hedge
effectiveness).
(26) Receivables and other financial assets measured at amortised cost are presented on the balance sheet net of their loss allowance.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 161
income, is reclassified to the profit and loss account when the
financial asset is derecognised. Currently the Group does not have
any financial assets measured at fair value through OCI.
A financial asset represented by a debt instrument that is neither
measured at amortised cost nor at FVTOCI, is measured at fair value
through profit or loss (hereinafter FVTPL); financial assets held for
trading fall into this category. Interest income on assets held for
trading contributes to the fair value measurement of the instrument
and is recognised in “Finance income (expense)”, within “Net
finance income (expense) from financial assets held for trading”.
When the purchase or sale of a financial asset is under a contract
whose terms require delivery of the asset within the time frame
established generally by regulation or convention in the marketplace
concerned, the transaction is accounted for on the settlement date.
IMPAIRMENT OF FINANCIAL ASSETS
The expected credit loss model is adopted for the impairment of
financial assets that are debt instruments, but are not measured
at fair value through profit or loss.
In particular, the expected credit losses are generally measured
by multiplying: (i) the exposure to the counterparty’s credit
risk net of any collateral held and other credit enhancements
(Exposure At Default, EAD); (ii) the probability that the default of
the counterparty occurs (Probability of Default, PD); and (iii) the
percentage estimate of the exposure that will not be recovered
in case of default (Loss Given Default, LGD), considering the past
experiences and the range of recovery tools that can be activated
(e.g. extrajudicial and/or legal proceedings, etc.).
With reference to trade and other receivables, Probabilities
of Default of counterparties are determined by adopting the
internal credit ratings already used for credit worthiness and are
periodically reviewed using, inter alia, back-testing analyses; for
government entities (e.g. National Oil Companies), the Probability
of Default, represented essentially by the probability of a delayed
payment, is determined by using, as input data, the country risk
premium adopted to determine WACC for the impairment review of
non-financial assets.
For customers without internal credit ratings, the expected credit
losses are measured by using a provision matrix, defined by
grouping, where appropriate, receivables into adequate clusters
to which apply expected loss rates defined on the basis of their
historical credit loss experiences, adjusted, where appropriate, to
take into account forward-looking information on credit risk of the
counterparty or clusters of counterparties27.
Considering the characteristics of the reference markets, financial
assets with more than 180 days past due or, in any case, with
counterparties undergoing litigation, restructuring or renegotiation,
are considered to be in default. Counterparties are considered
undergoing litigation when judicial/legal proceedings aimed
to recover a receivable have been activated or are going to be
activated. Impairment losses of trade and other receivables are
recognised in the profit and loss account, net of any impairment
reversal, within the line item of the profit and loss account “Net
(impairment losses) reversals of trade and other receivables”.
The financing receivables held for operating purposes, granted
to associates and joint ventures, for which settlement is neither
planned nor likely to occur in the foreseeable future and which
in substance form part of the entity’s net investment in these
investees, are tested for impairment, first, on the basis of the
expected credit loss model and, then, together with the carrying
amount of the investment in the associate/joint venture, in
accordance with the criteria indicated in the accounting policy for
“The equity method of accounting”. In applying the expected credit
loss model, any adjustments to the carrying amount of long-term
interest that arise from applying the accounting policy for “The
equity method of accounting” are not taken into account.
Significant accounting estimates and judgements: impairment of
financial assets
Measuring impairment losses of financial assets requires
management evaluation of complex and highly uncertain elements
such as, for example, Probabilities of Default of counterparties, the
existence of any collateral or other credit enhancements, the expected
exposure that will not be recovered in case of default, as well as the
definition of customers' clusters to be adopted.
INVESTMENTS IN EQUITY INSTRUMENTS
Investments in equity instruments that are not held for trading
are measured at fair value through other comprehensive income,
without subsequent transfer of fair value changes to profit or loss
on derecognition of these investments; conversely, dividends from
these investments are recognised in the profit and loss account,
within the line item “Income (Expense) from investments”,
unless they clearly represent a recovery of part of the cost of the
investment. In limited circumstances, an investment in equity
instruments can be measured at cost if it is an appropriate estimate
of fair value.
FINANCIAL LIABILITIES
At initial recognition, financial liabilities, other than derivative financial
instruments, are measured at their fair value, minus transaction costs
that are directly attributable, and are subsequently measured at
amortised cost.
DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGE
ACCOUNTING
Derivative financial instruments, including embedded derivatives
(see below) that are separated from the host contract, are assets and
liabilities measured at their fair value.
With reference to the defined risk management objectives and
strategy, the qualifying criteria for hedge accounting requires: (i)
the existence of an economic relationship between the hedged
item and the hedging instrument in order to offset the related value
changes and the effects of counterparty credit risk do not dominate
the economic relationship between the hedged item and the hedging
instrument; and (ii) the definition of the relationship between the
(27) For credit exposures arising from intragroup transactions, the recovery rate is normally assumed equal to 100% taking into account, inter alia, the Group central treasury function which supports both
financial and capital needs of subsidiaries.
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quantity of the hedged item and the quantity of the hedging instrument
(the so-called hedge ratio) consistent with the entity’s risk management
objectives, under a defined risk management strategy; the hedge ratio
is adjusted, where appropriate, after taking into account any adequate
rebalancing. A hedging relationship is discontinued prospectively, in its
entirety or a part of it, when it no longer meets the risk management
objectives on the basis of which it qualified for hedge accounting, it
ceases to meet the other qualifying criteria or after rebalancing it.
When derivatives hedge the risk of changes in the fair value of the
hedged items (fair value hedge, e.g. hedging of the variability in the
fair value of fixed interest rate assets/liabilities), the derivatives are
measured at fair value through profit and loss account. Consistently,
the carrying amount of the hedged item is adjusted to reflect, in the
profit and loss account, the changes in fair value of the hedged item
attributable to the hedged risk; this applies even if the hedged item
should be otherwise measured.
When derivatives hedge the exposure to variability in cash flows
of the hedged items (cash flow hedge, e.g. hedging the variability
in the cash flows of assets/liabilities as a result of the fluctuations
of exchange rate), the effective changes in the fair value of the
derivatives are initially recognised in the equity reserve related to
other comprehensive income and then reclassified to the profit and
loss account in the same period during which the hedged transaction
affects the profit and loss account.
If a hedged forecast transaction subsequently results in the recognition
of a non-financial asset or a non-financial liability, the accumulated
changes in fair value of hedging derivatives recognised in equity, are
included directly in the carrying amount of the hedged non-financial
asset/liability (commonly referred to as a “basis adjustment”).
The changes in the fair value of derivatives that are not designated
as hedging instruments, including any ineffective portion of changes
in fair value of hedging derivatives, are recognised in the profit
and loss account. In particular, the changes in the fair value of
non-hedging derivatives on interest rates and exchange rates are
recognised in the profit and loss account line item “Finance income
(expense)”; conversely, the changes in the fair value of non-hedging
derivatives on commodities are recognised in the profit and loss
account line item “Other operating (expense) income”. Derivatives
embedded in financial assets are not accounted for separately; in such
circumstances, the entire hybrid instrument is classified depending on
the contractual cash flow characteristics of the financial instrument
and the business model for managing it (see the accounting policy for
“Financial assets”). Derivatives embedded in financial liabilities and/or
non-financial assets are separated if: (i) the economic characteristics
and risks of the embedded derivative are not closely related to the
economic characteristics and risks of the host contract; (ii) a separate
instrument with the same terms as the embedded derivative would
meet the definition of a derivative; and (iii) the entire hybrid contract
is not measured at FVTPL.
Eni assesses the existence of embedded derivatives to be separated
when it becomes party to the contract and, afterwards, when a change
in the terms of the contract that modifies its cash flows occurs.
Contracts to buy or sell commodities entered into and continued to be
held for the purpose of their receipt or delivery in accordance with the
Group’s expected purchase, sale or usage requirements are recognised
on an accrual basis (the so-called normal sale and normal purchase
exemption or own use exemption).
OFFSETTING OF FINANCIAL ASSETS AND LIABILITIES
Financial assets and liabilities are set off on the balance sheet if the
Group currently has a legally enforceable right to set off and intends
to settle on a net basis (or to realise the asset and settle the liability
simultaneously).
DERECOGNITION OF FINANCIAL ASSETS AND LIABILITIES
Transferred financial assets are derecognised when the contractual
rights to receive the cash flows from the financial assets expire or
are transferred to another party. Financial liabilities are derecognised
when they are extinguished, or when the obligation specified in the
contract is discharged, cancelled or expired.
CASH AND CASH EQUIVALENTS
Cash and cash equivalents include cash on hand, demand deposits,
as well as financial assets originally due, generally, within 90 days,
readily convertible to known amount of cash and subject to an
insignificant risk of changes in value.
PROVISIONS, CONTINGENT LIABILITIES AND
CONTINGENT ASSETS
A provision is a liability of uncertain timing or amount on the
balance sheet date. Provisions are recognised when: (i) there is
a present obligation, legal or constructive, as a result of a past
event; (ii) it is probable that an outflow of resources embodying
economic benefits will be required to settle the obligation; and (iii)
the amount of the obligation can be reliably estimated. The amount
recognised as a provision is the best estimate of the expenditure
required to settle the present obligation or to transfer it to third
parties at the balance sheet date. The amount recognised for
onerous contracts is the lower of the cost necessary to fulfill the
obligations, net of expected economic benefits deriving from the
contracts, and any compensation or penalties arising from failure
to fulfill these obligations. Where the effect of the time value is
material, and the payment date of the obligations can be reasonably
estimated, provisions to be accrued are the present value of the
expenditures expected to be required to settle the obligation at a
discount rate that reflects the Company’s average borrowing rate
taking into account the risks associated with the obligation. The
increase in the provision due to the passage of time is recognised
as “Finance income (expense)”.
A provision for restructuring costs is recognised only when the
Company has a detailed formal plan for the restructuring and has
raised a valid expectation in the affected parties that it will carry
out the restructuring.
Provisions are periodically reviewed and adjusted to reflect changes
in the estimates of costs, timing and discount rates. Changes in
provisions are recognised in the same profit and loss account line
item where the original provision was charged.
Contingent liabilities are: (i) possible obligations arising from past
events, whose existence will be confirmed only by the occurrence or
non-occurrence of one or more uncertain future events not wholly
within the control of the Company; or (ii) present obligations arising
from past events, whose amount cannot be reliably measured or
whose settlement will probably not result in an outflow of resources
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163
embodying economic benefits. Contingent liabilities are not recognised
in the financial statements, but are disclosed.
Contingent assets, that are possible assets arising from past events
and whose existence will be confirmed only by the occurrence or non-
occurrence of one or more uncertain future events not wholly within
the control of the Company, are not recognised unless the realisation
of economic benefits is virtually certain. Contingent assets are
disclosed when an inflow of economic benefits is probable.
Contingent assets are assessed periodically to ensure that
developments are appropriately reflected in the financial statements;
if it has become virtually certain that an inflow of economic benefits
will arise, the asset and the related income are recognised in the
financial statements of the period in which the change occurs.
DECOMMISSIONING AND RESTORATION LIABILITIES
Liabilities for decommissioning and restoration costs are
recognized, together with a corresponding amount as part
of the related property, plant and equipment, when the Group
has a legal or constructive obligation and when a reliable estimate
can be made28.
Considering the long time span between the recognition of the
obligation and its settlement, the amount recognised is the present
value of the future expenditures expected to be required to settle
the obligation. The increase in the provision due to the unwinding of
the discount is recognised as “Finance income (expense)”.
Such liabilities are reviewed regularly to take into account
the changes in the expected costs to be incurred, contractual
obligations, regulatory requirements and practices in force in the
Countries where the tangible assets are located.
The effects of any changes in the estimate of the liability are
recognised generally as an adjustment to the carrying amount of
the related property, plant and equipment; however, if the resulting
decrease in the liability exceeds the carrying amount of the related
asset, the excess is recognised in the profit and loss account.
Significant accounting estimates and judgements: decommissioning
and restoration liabilities, environmental liabilities and other
provisions
The Group holds provisions for dismantling and removing items of
property, plant and equipment, and restoring land or seabed at the end
of the Oil & Gas production activity. Estimating obligations to dismantle,
remove and restore items of property, plant and equipment is complex. It
requires management to make estimates and judgements with respect
to removal obligations that will come to term many years into the future
and contracts and regulations are often unclear as to what constitutes
removal. In addition, the ultimate financial impact of environmental laws
and regulations is not always clearly known as asset removal technologies
and costs constantly evolve in the Countries where Eni operates, as do
political, environmental, safety and public expectations.
The discount rate used to determine the provision and the timing of
future cash outflows, as well as any related update, are based on
complex managerial judgements.
As other oil and gas companies, Eni is subject to numerous EU, national,
regional and local environmental laws and regulations concerning its
oil and gas operations, production and other activities. They include
legislations that implement international conventions or protocols.
Environmental liabilities are recognised when it becomes probable that
an outflow of resources will be required to settle the obligation and such
obligation can be reliably estimated29.
Management, considering the actions already taken, insurance
policies obtained to cover environmental risks and provisions already
recognised, does not expect any material adverse effect on Eni’s
consolidated results of operations and financial position as a result of
such laws and regulations. However, there can be no assurance that
there will not be a material adverse impact on Eni’s consolidated results
of operations and financial position due to: (i) the possibility of an
unknown contamination; (ii) the results of the ongoing surveys and
other possible effects of statements required by applicable laws; (iii) the
possible effects of future environmental legislations and rules; (iv) the
effects of possible technological changes relating to future remediation;
and (v) the possibility of litigation and the difficulty of determining Eni’s
liability, if any, against other potentially responsible parties with respect
to such litigations and the possible reimbursements.
In addition to environmental and decommissioning and restoration
liabilities, Eni recognises provisions primarily related to legal and trade
proceedings. These provisions are estimated on the basis of complex
managerial judgements related to the amounts to be recognised
and the timing of future cash outflows. After the initial recognition,
provisions are periodically reviewed and adjusted to reflect the current
best estimate.
EMPLOYEE BENEFITS
Employee benefits are considerations given by the Group in exchange for
service rendered by employees or for the termination of employment.
Post-employment benefit plans, including informal arrangements, are
classified as either defined contribution plans or defined benefit plans
depending on the economic substance of the plan as derived from its
principal terms and conditions. Under defined contribution plans, the
Company’s obligation, which consists in making payments to the State
or to a trust or a fund, is determined on the basis of contributions due.
The liabilities related to defined benefit plans, net of any plan assets,
are determined on the basis of actuarial assumptions and charged
on an accrual basis during the employment period required to obtain
the benefits.
Net interest includes the return on plan assets and the interest cost to
be recognised in the profit and loss account. Net interest is measured by
applying to the liability, net of any plan assets, the discount rate used to
calculate the present value of the liability; net interest of defined benefit
plans is recognised in “Finance income (expense)”.
Remeasurements of the net defined benefit liability, comprising
actuarial gains and losses, resulting from changes in the actuarial
assumptions used or from changes arising from experience
adjustments, and the return on plan assets excluding amounts
included in net interest, are recognised within the statement of
(28) These liabilities relate essentially to the Exploration & Production segment’s assets. The decommissioning and restoration liabilities associated with the Refining & Marketing and Chemicals and
Gas & Power segments’ assets are generally not recognised, as the obligations cannot be reliably estimated, given their indeterminate settlement dates. In this regard, Eni performs periodic reviews of
Refining & Marketing and Chemicals and Gas & Power segments’ tangible assets for any changes in facts and circumstances that might require recognition of a decommissioning and restoration liability.
(29) With reference to the environmental liabilities assumed, the expected operating costs to be incurred for managing groundwater treatment plants are not included in the estimates of environmental
liabilities because it is not possible to reliably define a time horizon within which the operations of the plant will be terminated. In this regard, Eni performs periodic reviews for any changes in facts and
circumstances, including changes in regulatory framework and technology, that might require the recognition of the environmental liability.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019 164
comprehensive income. Remeasurements of the net defined benefit
liability, recognised within other comprehensive income, are not
reclassified subsequently to the profit and loss account.
Obligations for long-term benefits are determined by adopting actuarial
assumptions. The effects of remeasurements are taken to profit and
loss account in their entirety.
previous actuarial assumptions and what has actually occurred and
differences in the return on plan assets, excluding amounts included
in net interest, usually occur. Similar to the approach followed for
the fair value measurement of financial instruments, the fair value
of the shares underlying the incentive plans is measured by using
complex valuation techniques and identifying, through structured
judgements, the assumptions to be adopted.
SHARE-BASED PAYMENTS
The line item “Payroll and related costs” includes the cost of the
share-based incentive plan, consistent with its actual remunerative
nature30. The cost of the share-based incentive plan is measured
by reference to the fair value of the equity instruments granted and
the estimate of the number of shares that eventually vest; the cost
is recognised on an accrual basis pro rata temporis over the vesting
period, that is the period between the grant date and the settlement
date. The fair value of the shares underlying the incentive plan is
measured at the grant date, taking into account the estimate of
achievement of market conditions (e.g. Total Shareholder Return),
and is not adjusted in subsequent periods; when the achievement
is linked also to non-market conditions, the number of shares
expected to vest is adjusted during the vesting period to reflect the
updated estimate of these conditions. If, at the end of the vesting
period, the incentive plan does not vest because of failure to satisfy
the performance conditions, the portion of cost related to market
conditions is not reversed to the profit and loss account.
Significant accounting estimates and judgements: employee
benefits and share-based payments
Defined benefit plans are evaluated with reference to uncertain
events and based upon actuarial assumptions including, among
others, discount rates, expected rates of salary increases, mortality
rates, estimated retirement dates and medical cost trends. The
significant assumptions used to account for defined benefit plans
are determined as follows: (i) discount and inflation rates are
based on the market yields on high quality corporate bonds (or,
in the absence of a deep market of these bonds, on the market
yields on government bonds) and on the expected inflation rates
in the reference currency area; (ii) the future salary levels of the
individual employees are determined including an estimate of
future changes attributed to general price levels (consistent with
inflation rate assumptions), productivity, seniority and promotion;
(iii) healthcare cost trend assumptions reflect an estimate of the
actual future changes in the cost of the healthcare related benefits
provided to the plan participants and are based on past and current
healthcare cost trends, including healthcare inflation, changes in
healthcare utilisation, changes in health status of the participants
and the contributions paid to health funds; and (iv) demographic
assumptions such as mortality, disability and turnover reflect the
best estimate of these future events for individual employees
involved.
Differences in the amount of the net defined benefit liability (asset),
deriving from the remeasurements, comprising, among others,
changes in the current actuarial assumptions, differences in the
TREASURY SHARES
Treasury shares, including shares held to meet the future
requirements of the share-based incentive plans, are recognised
as deductions from equity at cost. Any gain or loss resulting from
subsequent sales is recognised in equity.
REVENUE FROM CONTRACTS WITH CUSTOMERS
Revenue from contracts with customers is recognised on the
basis of the following five steps: (i) identifying the contract with
the customer; (ii) identifying the performance obligations, that
are promises in a contract to transfer goods and/or services to a
customer; (iii) determining the transaction price; (iv) allocating the
transaction price to each performance obligation on the basis of
the relative stand-alone selling prices of each good or service; and
(v) recognising revenue when (or as) a performance obligation is
satisfied, that is when a promised good or service is transferred to a
customer. A promised good or service is transferred when (or as) the
customer obtains control of it. Control can be transferred over time or
at a point in time. With reference to the most important products sold
by Eni, revenue is generally recognised for:
- crude oil, upon shipment;
- natural gas and electricity, upon delivery to the customer;
- petroleum products sold to retail distribution networks, upon
delivery to the service stations, whereas all other sales of
petroleum products are recognised upon shipment; and
- chemical products and other products, upon shipment.
Revenue from crude oil and natural gas production from properties
in which Eni has an interest together with other producers is
recognised on the basis of the quantities actually lifted and sold
(sales method); costs are recognised on the basis of the quantities
actually sold31.
Revenue is measured at the fair value of the consideration to which
the Company expects to be entitled in exchange for transferring
promised goods and/or services to a customer, excluding amounts
collected on behalf of third parties. In determining the transaction
price, the promised amount of consideration is adjusted for the
effects of the time value of money if the timing of payments agreed
to by the parties to the contract provides the customer or the entity
with a significant benefit of financing the transfer of goods or
services to the customer. The promised amount of consideration is
not adjusted for the effect of the significant financing component
if, at contract inception, it is expected that the period between the
transfer of a promised good or service to a customer and when the
customer pays for that good or service will be one year or less. If the
consideration promised in a contract includes a variable amount,
(30) The current share-based incentive plan, to be settled by treasury shares, was approved by the shareholders’ meeting held on April 13, 2017.
(31) In accordance with the accounting policy adopted until 2017 (entitlement method, before applying IFRS 15), revenue from crude oil and natural gas production from properties in which Eni has an
interest together with other producers were recognised on the basis of Eni’s net working interest in those properties. On the balance sheet, lifting imbalances were recognised respectively as payables
and receivables and measured at current prices at the balance sheet date.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 165
the Company estimates the amount of consideration to which it will
be entitled in exchange for transferring the promised goods and/or
services to a customer; in particular, the amount of consideration can
vary because of discounts, refunds, incentives, price concessions,
performance bonuses, penalties or if the price is contingent on the
occurrence or non-occurrence of future events.
If, in a contract, the Company grants a customer the option to
acquire additional goods or services for free or at a discount (e.g.
sales incentives, customer award points, etc.), this option gives
rise to a separate performance obligation in the contract only if the
option provides a material right to the customer that it would not
receive without entering into that contract. When goods or services
are exchanged for goods or services which are of a similar nature
and value, the exchange is not regarded as a transaction which
generates revenue.
Significant accounting estimates and judgements: revenue from
contracts with customers
Revenue from sales of electricity and gas to retail customers
includes amount accrued for electricity and gas supplied between
the date of the last invoiced meter reading (actual or estimated)
of volumes consumed and the end of the year. These estimates
consider mainly information provided by the grid managers about
the volumes allocated among the customers of the secondary
distribution network, about the actual and estimated volumes
consumed by customers. Therefore, revenue is accrued as a result of
a complex estimate based on the volumes distributed and allocated,
communicated by third parties, likely to be adjusted, according to
applicable regulations, within the fifth year following the one in which
they are accrued. Considering the contractual obligations on the
supply delivery points, revenue from sales of electricity and gas to
retail customers includes costs for transportation and dispatching
and in these cases the gross amount of consideration to which the
Company is entitled is recognised.
COSTS
Costs are recognised when the related goods and services are sold or
consumed during the year, when they are allocated on a systematic
basis or when their future economic benefits cannot be identified. Costs
associated with emission quotas, incurred to meet the compliance
requirements (e.g. Emission Trading Scheme) determined on the basis
of market prices, are recognised in relation to the amounts of the carbon
dioxide emissions that exceed free allowances. Costs related to the
purchase of the emission rights that exceed the amount necessary
to meet regulatory obligations are recognised as intangible assets.
Revenue related to emission quotas is recognised when they are sold.
Monetary receivables granted to replace the free award emission rights
are recognised as a contra to the line item “Other income and revenues”.
The costs incurred on a voluntary basis for the acquisition or production
of forestry certificates, also taking into account the absence of an active
market, are recognised in the profit and loss account when incurred.
The costs for the acquisition of new knowledge or discoveries, the
study of products or alternative processes, new techniques or
models, the planning and construction of prototypes or, in any case,
costs incurred for other scientific research activities or technological
development, which cannot be capitalised (see also the accounting
policy for “Intangible assets”), are included in the profit and loss
account when they are incurred.
EXCHANGE DIFFERENCES
Revenues and costs associated with transactions in foreign currencies are
translated into the functional currency by applying the exchange rate at
the date of the transaction. Monetary assets and liabilities denominated
in foreign currencies are translated into the functional currency at the
spot exchange rate on the balance sheet date and any resulting exchange
differences are included in the profit and loss account within “Finance
income (expense)” or, if designated as hedging instruments for the
foreign currency risk, in the same line item in which the economic effects
of the hedged item are recognised. Non-monetary assets and liabilities
denominated in foreign currencies, measured at cost, are not retranslated
subsequent to initial recognition. Non-monetary items measured at fair
value, recoverable amount or net realisable value are retranslated using
the exchange rate at the date when the value is determined.
DIVIDENDS
Dividends are recognised when the right to receive payment of the
dividend is established.
Dividends and interim dividends to owners are shown as changes in
equity when the dividends are declared by, respectively, the shareholders’
meeting and the Board of Directors.
INCOME TAXES
Current income taxes are determined on the basis of estimated
taxable profit. Current income tax assets and liabilities are measured
at the amount expected to be paid to (recovered from) the taxation
authorities, using tax rates and the tax laws that have been enacted or
substantively enacted by the end of the reporting period.
Deferred tax assets and liabilities are recognised for temporary
differences arising between the carrying amounts of the assets
and liabilities and their tax bases, based on tax rates and tax laws
that are expected to apply to the period when the asset is realised
or the liability is settled, based on tax rates and tax laws that have
been enacted or substantively enacted by the end of the reporting
period. Deferred tax assets are recognised when their recoverability
is considered probable, i.e. when it is probable that sufficient taxable
profit will be available in the same year as the reversal of the
deductible temporary difference. Similarly, deferred tax assets for
the carry-forward of unused tax credits and unused tax losses are
recognised to the extent that their recoverability is probable. The
carrying amount of the deferred tax assets is reviewed, at least, on an
annual basis.
If there is uncertainty over income tax treatments, if the company
concludes it is probable that the taxation authority will accept an
uncertain tax treatment, it determines the (current and/or deferred)
income taxes to be recognised in the financial statements consistent
with the tax treatment used or planned to be used in its income tax
filings. Conversely, if the Company concludes it is not probable that the
taxation authority will accept an uncertain tax treatment, the Company
reflects the effect of uncertainty in determining the (current and/or
deferred) income taxes to be recognised in the financial statements.
Relating to the taxable temporary differences associated with
investments in subsidiaries and associates, and interests in joint
arrangements, the related deferred tax liabilities are not recognised
if the investor is able to control the timing of the reversal of the
temporary differences and it is probable that the temporary
differences will not reverse in the foreseeable future. Deferred tax
assets and liabilities are presented within non-current assets and
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019 166
liabilities and are offset at a single entity level if related to off-settable
taxes. The balance of the offset, if positive, is recognised in the line
item “Deferred tax assets” and, if negative, in the line item “Deferred
tax liabilities”. When the results of transactions are recognised directly
in shareholders’ equity, the related current and deferred taxes are also
charged to the shareholders’ equity.
Significant accounting estimates and judgements: income taxes
The computation of income taxes involves the interpretation
of applicable tax laws and regulations in many jurisdictions
throughout the world. Although Eni aims to maintain a relationship
with the taxation authorities characterised by transparency,
dialogue and cooperation (e.g. by not using aggressive tax planning
and by using, if available, procedures intended to eliminate or
reduce tax litigations), there can be no assurance that there will not
be a tax litigation with the taxation authorities where the legislation
could be open to more than one interpretation. The resolution of tax
disputes, through negotiations with relevant taxation authorities
or through litigation, could take several years to complete. The
estimate of liabilities related to uncertain tax treatments requires
complex judgements by management. After the initial recognition,
these liabilities are periodically reviewed for any changes in facts
and circumstances.
Moreover, management makes complex judgements regarding the
assessment of the recoverability of deferred tax assets, related
both to deductible temporary differences and unused tax losses,
which requires estimates and evaluations about the amount and
the timing of future taxable profits.
ASSETS HELD FOR SALE AND DISCONTINUED OPERATIONS
Non-current assets and current and non-current assets included
within disposal groups, are classified as held for sale if their
carrying amounts will be recovered principally through a sale
transaction rather than through their continuing use. This condition
is regarded as met only when the sale is highly probable and the
asset or the disposal group is available for immediate sale in its
present condition. When there is a sale plan involving loss of control
of a subsidiary, all the assets and liabilities of that subsidiary are
classified as held for sale, regardless of whether a non-controlling
interest in its former subsidiary will be retained after the sale.
Non-current assets held for sale, current and non-current assets
included within disposal groups that have been classified as held for
sale and the liabilities directly associated with them are recognised
on the balance sheet separately from other assets and liabilities.
Immediately before the initial classification of a non-current
asset and/or a disposal group as held for sale, the non-current
asset and/or the assets and liabilities in the disposal group are
measured in accordance with applicable IFRSs. Subsequently,
non-current assets held for sale are not depreciated or amortised
and they are measured at the lower of the fair value less costs
to sell and their carrying amount. If an equity-accounted
investment, or a portion of that investment meets the criteria to
be classified as held for sale, it is no longer accounted for using
the equity method and it is measured at the lower of its carrying
amount at the date the equity method is discontinued, and its
fair value less costs to sell. Any retained portion of the equity-
accounted investment that has not been classified as held for
sale is accounted for using the equity method until disposal of
the portion that is classified as held for sale takes place. After
the disposal, any retained interest in the investee is measured
in accordance with the measurement criteria indicated in the
accounting policy for “Investments in equity instruments”,
unless the retained interest continues to be an equity-accounted
investment.
Any difference between the carrying amount of the non-current
assets and the fair value less costs to sell is taken to the profit
and loss account as an impairment loss; any subsequent reversal
is recognised up to the cumulative impairment losses, including
those recognised prior to qualification of the asset as held for sale.
Non-current assets classified as held for sale and disposal groups
are considered a discontinued operation if they, alternatively: (i)
represent a separate major line of business or geographical area of
operations; (ii) are part of a disposal program of a separate major
line of business or geographical area of operations; or (iii) are a
subsidiary acquired exclusively with a view to resale. The results of
discontinued operations, as well as any gain or loss recognised on
the disposal, are indicated in a separate line item of the profit and
loss account, net of the related tax effects; the economic figures
of discontinued operations are indicated also for prior periods
presented in the financial statements.
If events or circumstances occur that no longer allow to classify a
non-current asset or a disposal group as held for sale, the non-
current asset or the disposal group is reclassified into the original
line items of the balance sheet and measured at the lower of: (i)
its carrying amount at the date of classification as held for sale
adjusted for any depreciation, amortisation impairment losses
and reversals that would have been recognised had the asset or
disposal group not been classified as held for sale, and (ii) its
recoverable amount at the date of the subsequent decision not to
sell. If the interruption of a plan of sale concerns a subsidiary, joint
operation, joint venture, associate, or a portion of an interest in a
joint venture or an associate, financial statements for the period
since classification as held for sale are amended.
FAIR VALUE MEASUREMENTS
Fair value is the price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market participants
(not in a forced liquidation or a distress sale) at the measurement date
(exit price). Fair value measurement is based on the market conditions
existing at the measurement date and on the assumptions of market
participants (market-based measurement). A fair value measurement
assumes that the transaction to sell the asset or transfer the liability
takes place in the principal market for the asset or liability, or in the
absence of a principal market, in the most advantageous market to
which the entity has access, independently from the entity’s intention to
sell the asset or transfer the liability to be measured.
A fair value measurement of a non-financial asset takes into
account a market participant’s ability to generate economic
benefits by using the asset in its highest and best use or by selling
it to another market participant that would use the asset in its
highest and best use. Highest and best use is determined from
the perspective of market participants, even if the entity intends
a different use; an entity’s current use of a non-financial asset is
presumed to be its highest and best use, unless market or other
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 167
factors suggest that a different use by market participants would
maximise the value of the asset.
The fair value of a liability, both financial and non-financial, or of
the Company’s own equity instrument, in the absence of a quoted
price, is measured from the perspective of a market participant
that holds the identical item as an asset at the measurement
date. The fair value of financial instruments takes into account the
counterparty’s credit risk for a financial asset (Credit Valuation
Adjustment, CVA) and the Company’s own credit risk for a financial
liability (Debit Valuation Adjustment, DVA). In the absence of
available market quotation, fair value is measured by using
valuation techniques that are appropriate in the circumstances,
maximising the use of relevant observable inputs and minimising
the use of unobservable inputs.
Significant accounting estimates and judgements: fair value
Fair value measurement, although based on the best available
information and on the use of appropriate valuation techniques, is
inherently uncertain, requires the use of professional judgement
and could result in expected values other than the actual ones.
2 | Primary financial statements32
Assets and liabilities on the balance sheet are classified as current
and non-current. Items in the profit and loss account are presented
by nature33. Assets and liabilities are classified as current when:
(i) they are expected to be realised/settled in the entity’s normal
operating cycle or within twelve months after the balance sheet date;
(ii) they are cash or cash equivalents unless they are restricted
from being exchanged or used to settle a liability for at least twelve
months after the balance sheet date; or (iii) they are held primarily
for the purpose of trading. Derivative financial instruments held for
trading are classified as current, apart from their maturity date. Non
hedging derivative financial instruments, which are entered into to
manage risk exposures but do not satisfy the formal requirements
to be considered as hedging, and hedging derivative financial
instruments are classified as current when they are expected to be
realised/settled within twelve months after the balance sheet date;
on the contrary they are classified as non-current.
The statement of comprehensive income (loss) shows net profit
integrated with income and expenses that are not recognised
directly in the profit and loss account according to IFRSs.
The statement of changes in shareholders’ equity includes the
total comprehensive income (loss) for the year, transactions with
shareholders in their capacity as shareholders and other changes in
shareholders’ equity.
The statement of cash flows is presented using the indirect method,
whereby net profit (loss) is adjusted for the effects of non-cash
transactions.
3 | Changes in accounting policies
Starting from January 1, 2019, Eni has applied IFRS 16 (hereinafter
IFRS 16), adopted by the Commission Regulation No. 2017/1986
issued by the European Commission on October 31, 2017, which
replaces IAS 17 and related interpretations. In particular, IFRS 16
eliminates the classification of leases as either operating leases or
finance leases for the preparation of lessees’ financial statements.
Conversely, a lessor continues to classify its leases as either operating
leases or finance leases. IFRS 16 enhances disclosures both for
lessees and lessors.
With reference to the lessee’s primary financial statements, starting
from January 1, 2019:
- on the balance sheet, right-of-use assets and lease liabilities are
-
-
recognised and presented separately from other assets and other
liabilities;
in the profit and loss account, depreciation charges and any
impairment losses/write offs of the right-of-use asset are recognised
within operating expenses and the interest expense on the lease
liability, if not capitalised, is recognised within finance expense rather
than recognising the operating lease payments within operating
expenses under IAS 17. The depreciation charges of the right-of-
use asset and the interest expenses on the lease liability directly
attributable to the construction of an asset are capitalised as part
of the cost of such asset and subsequently recognised in the profit
and loss account through depreciation/impairments or write off,
mainly in the case of exploration assets. Moreover, the profit and loss
account includes: (i) the expenses relating to short-term leases and
low-value leases; (ii) the expenses relating to variable lease payments
that are not included in the measurement of the lease liability (e.g.
payments that depend on the use of the underlying asset); and (iii)
the expenses relating to any non-lease components accounted for
separately from the lease component;
in the statement of cash flows, cash payments for the principal
portion of the lease liability are classified within financing activities,
whereas interest expense is classified within operating activities, if
they are recognised in the profit and loss account, or within investing
activities if they are capitalised in reference to leased assets that
are used for the construction of other assets34. Consequently,
compared to the requirements of IAS 17 related to operating leases,
the adoption of IFRS 16 has a significant impact in the statement
of cash flows, by determining: (a) an improvement of the net cash
provided by operating activities, which no longer includes operating
lease payments, not capitalised, but only includes the cash payments
for the interest portion of the lease liability that are not capitalised35;
(b) an improvement of the net cash used in investing activities, which
no longer includes capitalised lease payments, but only includes cash
payments for the capitalised interest portion of the lease liability; and
(c) a worsening in the net cash used in financing activities, which
includes cash payments for the principal portion of the lease liability.
(32) The impacts on the primary financial statements arising from the adoption, starting from January 1, 2019, of the new IFRSs, as well as the other changes in the primary financial statements, are
described in note 3 – Changes in accounting policies.
(33) Further information about classification of financial instruments is provided in note 27 – Guarantees, commitments and risks – Other information about financial instruments.
(34) The prepayments for right-of-use assets, made before the commencement date of lease contracts, are classified within investing activities.
(35) The net cash provided by operating activities will include also: (i) short-term lease payments and payments for low-value leases; (ii) variable lease payments not included in the measurement of
lease liabilities; and (iii) payments for non-lease components.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019 168
The adoption of the new requirements affects most of the Group
companies; in terms of amounts and/or volumes, the main cases
are the following: (i) in the Exploration & Production segment,
contracts for the lease of drilling rigs and floating production
storage and offloading vessels (the so-called FPSOs); (ii) in
the Refining & Marketing and Chemicals segment, highway
concessions, leases of land, service stations for the sale of oil
products, as well as the car fleet dedicated to the car sharing
business (enjoy); (iii) in the Gas & Power segment, leases of
vessels used for shipping activities and gas distribution facilities,
as well as tolling contracts; (iv) for Corporate activities, leases of
property.
IFRS 16 has been applied, starting from January 1, 2019, by
recognising, as allowed by the transition requirements of the
accounting standard, the cumulative effect of the initial application
as an adjustment to the opening balance of equity at January
1, 2019, with no restatement of comparative information (the
so-called modified retrospective approach). In particular, the
adoption of IFRS 16 resulted in the recognition of right-of-use
assets for €5.7 billion and lease liabilities for €5.8 billion; the
amount of the lease liabilities includes also the payables for lease
fees outstanding at January 1, 2019, previously classified as trade
payables. Such impacts take into account the indications of the
IFRS Interpretations Committee according to which, in the case
of unincorporated joint operations, the operator recognises the
entire lease liability, as, by signing the contract, it has primary
responsibility for the liability towards the third-party supplier.
Therefore, if based on the contractual provisions and any other
relevant facts and circumstances, Eni has primary responsibility,
it recognises on the balance sheet: (i) the entire lease liability and
(ii) the entire right-of-use asset, unless, based on the contractual
provisions, there is a sublease with the followers. In particular,
the amount of the lease liabilities at January 1, 2019, includes the
share of the lease liabilities corresponding to the followers’ working
interest for €2.0 billion, while the Eni working interest is €3.7 billion.
On initial application, Eni has elected to apply the following
practical expedients allowed by IFRS 16:
- possibility to not reassess each contract existing at January 1,
2019, by applying IFRS 16 to all contracts previously identified
as leases (under IAS 17 and IFRIC 4), while not applying IFRS 16
to contracts that were not previously identified as leases;
- for contracts previously classified as operating leases,
possibility to measure the right-of-use asset at an amount equal
to lease liability, adjusted, if necessary, by any prepaid amounts
already recognised on the balance sheet;
- as an alternative to performing an impairment review, possibility
to adjust the right-of-use asset, existing at January 1, 2019,
by the amount of any provision for onerous lease contracts
recognised at December 31, 2018;
- possibility to exclude initial direct costs from the measurement
of the right-of-use asset at January 1, 2019.
Moreover, on transition, Eni has elected to not consider leases for
which the lease term ends within 12 months of January 1, 2019 as
short-term leases.
The breakdown of the abovementioned quantitative effects and
reclassifications deriving from the initial application, as at January
1, 2019, of IFRS 16, is as follows:
(€ million)
Selected line items only
Current assets
of which: Trade and other receivables
Non-current assets
of which: Property, plant and equipment
of which: Right-of-use assets
Assets held for sale
Current liabilities
of which: Current portion of long-term debt
of which: Current portion of long-term lease liabilities
of which: Trade and other payables
Non-current liabilities
of which: Long-term debt
of which: Long-term lease liabilities
Liabilities directly associated with assets held for sale
December 31,
2018
Adoption of
IFRS 16
Reclassifications
IFRS 16
Total effect
of the first
application
As restated
January 1, 2019
39,450
14,101
78,628
60,302
295
28,382
3,601
16,747
38,859
20,082
59
5,656
5,656
665
665
4,991
4,991
(12)
(12)
(13)
(46)
33
13
(15)
(16)
129
(128)
(10)
(36)
26
13
(12)
(12)
5,643
(46)
5,689
39,438
14,089
84,271
60,256
5,689
13
308
650
(16)
794
(128)
4,981
(36)
5,017
29,032
3,585
794
16,619
43,840
20,046
5,017
13
72
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
169
The reconciliation between the amount of future minimum lease
payments under non-cancellable operating leases at December 31,
2018, discounted using the lessee's incremental borrowing rate at the
date of initial application of IFRS 16, and the opening balance of the
lease liabilities at January 1, 2019, is provided below:
(€ billion)
Future minimum lease payments under non-cancellable operating leases at December 31, 2018
- Recognition of the shares of leases related to followers
- Effect of discounting
- Extension options
- Other changes
Lease liability at January 1, 2019
4.0
2.0
(1.5)
1.2
0.1
5.8
In particular, the weighted average discount rate used to measure
the lease liabilities as at January 1, 2019 is equal to 6.8%.
Moreover, starting from January 1, 2019, the following IFRSs are
effective:
(i) the amendments to IAS 28 “Long-term Interests in Associates
and Joint Ventures”, adopted by the Commission Regulation
No. 2019/237 issued by the European Commission on February
8, 2019, which clarify that entities account for any financing
receivables towards an associate or joint venture, for which
settlement is neither planned nor likely to occur in the
foreseeable future (the so-called long-term interests), that,
in substance, form part of the entity’s net investment in the
investee, using the requirements of IFRS 9, including those
related to impairment. These amendments did not have a
significant impact on the Consolidated Financial Statements;
(ii) IFRIC 23 “Uncertainty over Income Tax Treatments”, adopted
by the Commission Regulation No. 2018/1595 issued by the
European Commission on October 23, 2018, which clarifies
the accounting for (current and/or deferred) tax assets and
liabilities when there is uncertainty over income tax treatments.
In particular, if there is uncertainty over income tax treatments,
if the Company concludes it is probable that the taxation
authority will accept an uncertain tax treatment, it determines
the (current and/or deferred) income taxes to be recognised
in the financial statements consistent with the tax treatment
used or planned to be used in its income tax filings. Conversely,
if the Company concludes it is not probable that the taxation
authority will accept an uncertain tax treatment, the company
reflects the effect of uncertainty in determining the (current
and/or deferred) income taxes to be recognised in the financial
statements. IFRIC 23 did not have a significant impact on the
measurement of income taxes. Nevertheless, with reference
to the presentation on the primary financial statements, in
September 2019, the IFRS Interpretations Committee has
indicated that the uncertain tax assets and liabilities shall be
presented in the line items where income tax assets and income
tax liabilities are recognised, and not in other line items. In this
regard, as the uncertain tax liabilities include also the provisions
for litigation concerning income taxes, these provisions have
been reclassified out of the line item “Provisions” into the new
line item “Income tax liabilities” within the non-current section
of the balance sheet. Moreover, the balance sheet has been
integrated with the new line items “Income tax assets”, within
the non-current section, to present assets (other than deferred
tax assets) related to income taxes, in specific, and not residual,
line items36.
Furthermore, starting from 2019, on the balance sheet, within the
current section, the line items “Other tax receivables” and “Other
tax payables” have been deleted and the related amounts have
been reclassified into the line items “Other assets” and “Other
liabilities”. This change has been carried out because the separate
presentation is not considered useful to understand the Group’s
financial position.
The balance sheet as at January 1, 2018 has been presented due
to the material effect of such reclassifications.
4 | IFRSs not yet effective
IFRSs ISSUED BY THE IASB AND ADOPTED BY THE EU
By the Commission Regulation No. 2019/2075 issued by the European
Commission on November 29, 2019, the document “Amendments
to References to the Conceptual Framework in IFRS Standards” was
adopted. The document includes, basically, technical and editorial
changes to existing IFRS standards in order to update references in those
standards to previous versions of the IFRS Framework with the new
Conceptual Framework for Financial Reporting, issued by the IASB on
the same date. These amendments shall be applied for annual reporting
periods beginning on or after January 1, 2020.
By the Commission Regulation No. 2019/2104 issued by the European
Commission on November 29, 2019, amendments to IAS 1 and IAS
8 “Definition of Material” (hereinafter the amendments to IAS 1 and
IAS 8) were adopted. The amendments to IAS 1 and IAS 8 clarify, and
align across all IFRS standards and other publications, the definition
of material to help companies make better materiality judgements. In
particular, information is material if omitting, misstating or obscuring
it could be expected to influence decisions that the primary users
of general purpose financial statements make on the basis of those
financial statements. The amendments to IAS 1 and IAS 8 shall be applied
for annual reporting periods beginning on or after January 1, 2020.
By the Commission Regulation No. 2020/34 issued by the European
Commission on January 15, 2020, amendments to IFRS 9, IAS 39 and
IFRS 7 “Interest Rate Benchmark Reform” (hereinafter amendments to
IFRS 9, IAS 39 and IFRS 7) were adopted. The amendments to IFRS 9,
(36) In previous reporting periods, income tax receivables and income tax payables were recognised within the non-current section of the balance sheet, respectively, in the line items “Other assets” and
“Other liabilities”.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019 170
IAS 39 and IFRS 7 provide temporary exceptions from applying specific
hedge accounting requirements to all hedging relationships directly
affected by the interest rate benchmark reform. The amendments to
IFRS 9, IAS 39 and IFRS 7 shall be applied for annual reporting periods
beginning on or after January 1, 2020.
IFRSs ISSUED BY THE IASB AND NOT YET ADOPTED BY
THE EU
On May 18, 2017, the IASB issued IFRS 17 “Insurance Contracts”
(hereinafter IFRS 17), which sets out the accounting for the
insurance contracts issued and the reinsurance contracts held. IFRS
17, which replaces IFRS 4 “Insurance Contracts”, shall be applied for
annual reporting periods beginning on or after January 1, 2021.
On October 22, 2018, the IASB issued amendments to IFRS 3
“Business Combinations” (hereinafter the amendments to IFRS 3),
which clarify the definition of a business. The amendments to IFRS
3 shall be applied for annual reporting periods beginning on or after
January 1, 2020.
On January 23, 2020, the IASB issued amendments to IAS 1
“Presentation of Financial Statements: Classification of Liabilities
as Current or Non-current” (hereinafter amendments to IAS 1),
which clarify how to classify debt and other liabilities as current or
non-current. The amendments to IAS 1 shall be applied for annual
reporting periods beginning on or after January 1, 2022.
Eni is currently reviewing the IFRSs not yet adopted in order
to determine the likely impact on the Consolidated Financial
Statements.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 171
5 | Cash and cash equivalents
Cash and cash equivalents of €5,994 million (€10,836 million at
December 31, 2018) included financial assets with maturity generally of
up to three months at the date of inception amounting to €3,984 million
(€8,732 million at December 31, 2018) and mainly included short-term
deposits in euro and US dollars with financial institutions, having notice
of more than 48 hours, to meet the Group’s short-term financing needs.
Restricted cash amounted to €198 million.
The average maturity of bank deposits in euro of €3,086 million was 9
days and the effective interest rate was a negative 0.22%; the average
maturity of bank deposits in US dollars of €864 million was 8 days with
an effective interest rate of 1.95%.
6 | Financial assets held for trading
(€ million)
Bonds issued by sovereign states
Other
December 31, 2019
1,462
5,298
6,760
December 31, 2018
1,083
5,469
6,552
The Company has established a liquidity reserve as part of its
internal targets and financial strategy with a view of ensuring an
adequate level of flexibility to the Group development plans and
of coping with unexpected fund requirements or difficulties in
accessing financial markets. The management of this liquidity
reserve is performed through trading activities in view of the
financial optimization of returns, within a predefined and authorized
level of risk tolerance, targeting the preservation of the invested
capital and the ability to promptly convert it into cash.
Financial assets held for trading include securities subject to lending
agreements of €1,347 million (€1,301 million at December 31,
2018).
The breakdown by currency is provided below:
(€ million)
Euro
US dollars
Other currencies
December 31, 2019
4,272
2,279
209
6,760
December 31, 2018
4,573
1,614
365
6,552
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019
172
The breakdown by issuing entity and credit rating is presented below:
Quoted bonds issued by sovereign states
Fixed rate bonds
Italy
Chile
Other(*)
Floating rate bonds
Italy
Germany
Other(*)
Total quoted bonds issued by sovereign states
Other Bonds
Fixed rate bonds
Quoted bonds issued by industrial companies
Quoted bonds issued by financial and insurance companies
Other bonds
Floating rate bonds
Quoted bonds issued by industrial companies
Quoted bonds issued by financial and insurance companies
Other bonds
Total other bonds
Total other financial assets held for trading
(*) Amounts included herein are lower than €50 million.
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734
177
216
1,127
126
106
81
313
1,440
1,183
862
105
2,150
1,530
1,116
444
3,090
5,240
6,680
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from Aaa to Baa1
BBB
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from AAA to BBB+
Baa3
Aaa
from Aaa to Baa3
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AAA
from AAA to BBB
from Aa2 to Baa3
from Aa3 to Baa3
from Aaa to Baa2
from AA to BBB-
from AA- to BBB-
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from AA+ to BBB-
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743
181
224
1,148
126
106
82
314
1,462
1,212
879
106
2,197
1,535
1,122
444
3,101
5,298
6,760
The fair value hierarchy is level 1 for €6,219 million and level 2 for €541 million. During 2019, there were no transfers between the different
hierarchy levels of fair value.
7 | Trade and other receivables
(€ million)
Trade receivables
Receivables from divestments
Receivables from joint ventures in exploration and production activities
Other receivables
December 31, 2019
8,519
30
2,637
1,687
12,873
December 31, 2018
9,520
122
3,024
1,435
14,101
Generally, trade receivables do not bear interest and provide
payment terms within 180 days.
Trade receivables decreased by €1,001 million, of which €874 million
related to the Gas & Power segment following a drop in prices and
volumes of gas sold in the fourth quarter 2019 compared to the same
period of 2018.
At December 31, 2019, Eni sold without recourse receivables due in
2020 for €1,782 million (€1,769 million at December 31, 2018 due in
2019). Derecognized receivables related to the Gas & Power segment
for €1,369 million and to the Refining & Marketing and Chemicals
segment for €413 million.
Receivables from divestments decreased by €92 million during
2019 due to the collection of the last installment of €123 million
related to the sale of a 10% interest in the Zohr asset in Egypt
made to BP in 2017.
Receivables from joint ventures in exploration and production activities
included amounts due by partners in unincorporated joint operations
in Nigeria for €1,052 million (€977 million at December 31, 2018) in
respect of the contractual recovery of expenditures incurred at certain
projects operated by Eni. The amount due by the Nigerian national
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
173
oil company NNPC was €764 million (€681 million at December 31,
2018), of which 70% is overdue. This overdue amount is subject to a
“Repayment Agreement”, whereby Eni is to be reimbursed through the
sale of the profit oil attributable to NNPC in certain rig-less petroleum
initiatives with low mineral risk. Based on Eni’s Brent price scenario, the
reimbursement will be accomplished over a time horizon of three to five
years. This plan has allowed to recover about 45% of the original amount
from the implementation of the agreement two years ago. The overdue
receivable is stated net of a discount factor. A local oil company owed
us about €113 million, net of a provision based on the loss given
default (LGD) defined by Eni for international oil companies. Initiatives
for the definition of a repayment plan are underway. A receivable of
equivalent amount was reclassified to non-current assets following
the definition of a repayment plan based on the attribution to Eni of
the proceeds for the sale of the productions attributable to the partner.
This receivable has been considered as performing because the
production is operated by Eni.
Other receivables comprised the recoverable amounts for €373
million (€300 million at December 31, 2018) of certain overdue trade
receivables towards the State-owned oil company of Venezuela, PDVSA,
in relation to gas equity volumes supplied by the joint venture Cardón
IV, equally participated by Eni and Repsol. Those trade receivables were
agreed to be transferred from the joint venture to the two shareholders.
The receivables are stated net of an allowance for doubtful accounts
determined on the basis of the average recovery percentages obtained
by creditors in the context of sovereign defaults, adjusted to reflect the
strategic value of the Oil & Gas sector, and also applied for assessing
the recoverability of the carrying amount of the investment and the
long-term interest in the initiative, as described in note 16 – Other
financial assets.
Trade and other receivables stated in euro and US dollars amounted to
€6,303 million and €5,480 million, respectively.
Credit risk exposure and expected losses relating to trade and other
receivables has been prepared on the basis of internal ratings as follows:
(€ million)
December 31, 2019
Business customers
National Oil Companies and public administrations
Other counterparties
Gross amount
Allowance for doubtful accounts
Net amount
Expected loss (% net of counterpart risk mitigation factors)
December 31, 2018
Business customers
National Oil Companies and public administrations
Other counterparties
Gross amount
Allowance for doubtful accounts
Net amount
Expected loss (% net of counterpart risk mitigation factors)
Performing receivables
Low
risk
Medium
Risk
High
Risk
Defaulted
receivables
Eni gas
e luce
customers
1,922
1,201
1,646
4,769
(13)
4,756
0.3
2,454
1,292
1,494
5,240
(9)
5,231
0.2
2,882
472
103
3,457
(4)
3,453
0.1
3,585
157
77
3,819
(3)
3,816
0.1
840
244
381
1,465
(16)
1,449
1.1
1,152
672
156
1,980
(44)
1,936
2.6
1,396
2,710
217
4,323
(2,547)
1,776
58.9
1,350
2,217
271
3,838
(2,237)
1,601
62.5
2,105
2,105
(666)
1,439
31.6
2,374
2,374
(857)
1,517
36.1
Total
7,040
4,627
4,452
16,119
(3,246)
12,873
20.1
8,541
4,338
4,372
17,251
(3,150)
14,101
18.3
Eni has classified its business customers and the associated
commercial or industrial exposures based on an individual
assessment of the credit merit and the counterparty risks. Business
customers other than National Oil Companies (NOC) and public
administrations, each of whom have undergone specific credit
evaluations, have been assigned a probability of default calculated
based on internal ratings which factor in: (i) a full assessment of each
customer profitability, financial condition and liquidity and business a
financial prospects on an ongoing basis; (ii) history of the contractual
relationship (timeliness in invoice payment, number of claims, etc.);
(iii) presence of mitigation factors of the credit risk (e.g. securitization
package, insurance against the credit risk, guarantee from third
parties, etc.); (iv) other specialized pieces of information obtained by
the Company’s business commercial departments or by specialized
info-providers; (v) industrial and market trends. Internal ratings and
the probability of default are constantly updated by means of back-
testing analysis and risk assessment of the current credit portfolio.
The loss given default associated with those industrial customers is
estimated by the business departments based on the past experience
in credit recoverability; in the case of defaulting customers, loss given
default is estimated based on the recovery rates obtained in situations
of credit restructurings or litigation procedures.
The probability of default associated with NOCs and public
administrations is estimated based on the country risk premium
incorporated in the risk-adjusted weighted average cost of capital
utilized by the Company to perform the impairment review of its fixed
assets. The loss given default of these business partners, essentially
represented by the probability of a delay in repaying due amounts,
is estimated based on historical averages of delays in collecting
overdue receivables, substantially assessing the time value of
money. The resulting loss given default is adjusted to factor in any
existing mitigation factor. In case of particular market conditions or
sovereign defaults, the expected loss associated with NOCs is re-
rated based on the empirical evidence and outcomes obtained from
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019
174
restructuring of sovereign debts considering the specificities of
trading relationships with energy companies. Customers of the Eni
subsidiary “Eni gas e luce”, which engages in marketing gas and
power to residential customers, were grouped into homogeneous
clusters with different credit risk and probability of default
which have been estimated based on past experience on credit
collection, systematically updated and, in case of particular market
conditions, adjusted to take into account expected market and
credit trends in any given cluster.
The exposure to credit risk and expected losses relating to retail
customers of the Gas & Power segment was assessed on the basis of a
provision matrix as follows:
(€ million)
December 31, 2019
Customers - Eni gas e luce:
- Retail
- Middle
- Other
Gross amount
Allowance for doubtful accounts
Net amount
Expected loss (%)
December 31, 2018
Customers - Eni gas e luce:
- Retail
- Middle
- Other
Gross amount
Allowance for doubtful accounts
Net amount
Expected loss (%)
Not-past due
from 0
to 3 months
from 3
to 6 months
from 6
to 12 months
over
12 months
Ageing
991
93
76
1,160
(16)
1,144
1.4
575
449
207
1,231
(20)
1,211
1.6
105
29
3
137
(27)
110
19.7
49
43
2
94
(18)
76
19.1
60
4
1
65
(26)
39
40.0
34
13
1
48
(18)
30
37.5
86
14
2
102
(49)
53
48.0
64
29
2
95
(56)
39
58.9
376
263
2
641
(548)
93
85.5
554
349
3
906
(745)
161
82.2
Total
1,618
403
84
2,105
(666)
1,439
31.6
1,276
883
215
2,374
(857)
1,517
36.1
Trade and other receivables are stated net of the allowance for doubtful accounts which has been determined considering the counterparty risk
mitigation factors amounting to €2,914 million (€3,072 million at December 31, 2018):
(€ million)
Carrying amount - beginning of the year
Changes in accounting policies (IFRS 9)
Carrying amount - restated
Additions on trade and other performing receivables
Additions on trade and other defaulted receivables
Deductions on trade and other performing receivables
Deductions on trade and other defaulted receivables
Other changes
Carrying amount - end of the year
2019
3,150
3,150
95
525
(119)
(484)
79
3,246
2018
2,639
427
3,066
126
372
(189)
(532)
307
3,150
Additions to allowance for doubtful accounts on trade and other performing
receivables related for €67 million (€108 million in 2018) to the Gas &
Power segment, particularly in the retail business; in the Exploration &
Production segment provisions of €23 million (€16 million in 2018) related
to cash calls towards joint operators – State oil Companies or International
Oil Companies – in oil projects operated by Eni.
Additions to allowance for doubtful accounts on trade and other defaulted
receivables related to the Exploration & Production segment for €339
million (€291 million in 2018) and were in relation with receivables for the
supply of equity hydrocarbons to State-owned companies and receivables
towards joint operators for cash calls in oil projects operated by Eni.
Utilizations of allowance for doubtful accounts on trade and other
performing and defaulted receivables amounted to €603 million (€721
million in 2018) and mainly related to the Gas & Power segment for €385
million (€613 million in 2018), in particular utilizations against charges
of €344 million (€579 million in 2018) mainly in the retail business.
The mitigation measures regarding the counterparty risk executed by
the Company, including better customer selection, allowed to reduce
the incidence of unpaid amounts on retail sales of gas and power to
physiological levels. Utilizations in Exploration & Production segment of
€177 million (€66 million in 2018) related to the progress in the collection
of overdue amounts for cash calls.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
Net (impairment losses) reversals of trade and other receivables are disclosed as follows:
(€ million)
Net (impairment losses) reversals of trade and other receivables
New or increased provisions
Credit losses
Reversals
Receivables with related parties are disclosed in note 36 – Transactions with related parties.
8 | Non-current and current inventories
Current inventories are disclosed as follows:
(€ million)
Raw and auxiliary materials and consumables
Consumables for infrastructure and facility maintenance of perforation activities
Finished products and goods
Work in progress
Certificates and emission rights
175
2019
2018
(620)
(45)
233
(432)
(498)
(37)
120
(415)
December 31, 2019
950
1,477
2,284
8
15
4,734
December 31, 2018
889
1,451
2,274
37
4,651
Raw and auxiliary materials and consumables include oil-based
feedstock, catalysts and other consumables pertaining to refining and
chemical activities.
Materials and supplies include materials to be consumed in drilling
activities and spare parts related to the Exploration & Production
segment for €1,359 million (€1,334 million at December 31, 2018).
Finished products and goods included gas and petroleum products for
€1,467 million (€1,543 million at December 31, 2018) and chemical
products for €547 million (same amount at December 31, 2018).
Certificates and emission rights are measured at the fair value based
on market prices. The fair value hierarchy is level 1.
Inventories of €95 million (same amount at December 31, 2018)
were pledged to guarantee the estimated imbalance in volumes
input to/off-taken from the national gas network operated by Snam
Rete Gas SpA.
Inventories are stated net of write-down provisions of €377 million
(€578 million at December 31, 2018).
Inventories held for compliance purposes of €1,371 million (€1,217
million at December 31, 2018) related to Italian subsidiaries for €1,353
million (€1,200 million at December 31, 2018) in accordance with
minimum stock requirements for oil and petroleum products set forth
by applicable laws.
9 | Income tax receivables and payables
(€ million)
Income taxes
December 31, 2019
December 31, 2018
Receivables
Current
192
Non-Current
173
Payables
Current
456
Non-Current
454
Receivables
Current
191
Non-Current
168
Payables
Current
440
Non-Current
287
Income taxes are described in note 32 – Income tax expense.
Non-current income tax payables include the likely outcome of
pending litigation with tax authorities in relation to uncertain
tax matters relating to foreign subsidiaries of the Exploration &
Production segment for €362 million (€255 million at December 31,
2018).
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019
176
10 | Other assets and liabilities
(€ million)
Fair value of derivate financial instruments
Contract liabilities
Other Taxes
Other
December 31, 2019
December 31, 2018
Assets
Current Non-Current
54
2,573
766
633
3,972
223
594
871
Liabilities
Current Non-Current
50
456
63
1,042
1,611
2,704
1,669
1,411
1,362
7,146
Assets
Current
1,594
Non-Current
68
561
664
2,819
254
302
624
Liabilities
Current
1,445
1,108
1,432
1,427
5,412
Non-Current
40
518
34
883
1,475
The fair value related to derivative financial instruments is disclosed
in note 23 – Derivative financial instruments and hedge accounting.
Assets related to other current taxes refer to VAT for €742 million,
of which €557 million are current, and related to advances made
in December (€608 million at December 31, 2018, of which €383
million current).
Other assets include: (i) gas volumes prepayments that were made
in previous years due to the take-or-pay obligations in relation to the
Company’s long-term supply contracts of €174 million (€26 million
at December 31, 2018); in 2019 the Company opted to increase
the take-or-pay advance with a view of optimizing its gas portfolio,
expecting to recover the underlying volumes within the next year; (ii)
non-current receivables for investing activities for €11 million (€9
million at December 31, 2018).
Contract liabilities included: (i) advances denominated in local
currency of €1,228 million (€716 million at December 31, 2018) to
offset future supplies of equity hydrocarbons to our Egyptian State-
owned partners in relation to the operations of Eni’s Concession
Agreements in the Country, in particular, among these, the Zohr
project; (ii) the current portion of advances received by Engie SA
(former Suez) relating to a long-term agreement for supplying
natural gas and electricity for €64 million (€66 million at December
31, 2018); the non-current portion amounted to €455 million (€518
million at December 31, 2018).
Other current liabilities included overlifting imbalances of the
Exploration & Production segment for €917 million (€1,004 million at
December 31, 2018).
Liabilities related to other current taxes include excise duties and
consumer taxes for €628 million (€636 million at December 31,
2018) and VAT liabilities for €311 million (€359 million at December
31, 2018).
Other non-current liabilities include cautionary deposits from retail
customers for the supply of gas and electricity of €231 million (€233
million at December 31 2018).
Transactions with related parties are described in note 36 –
Transactions with related parties.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 177
11 | Property, plant and equipment
(€ million)
2019
Net carrying amount - beginning of the year
Additions
Depreciation capitalized
Depreciation(a)
Reversals
Impairment
Write-off
Disposals
Currency translation differences
Initial recognition and changes in estimates
Transfers
Other changes
Net carrying amount - end of the year
Gross carrying amount - end of the year
Provisions for depreciation and impairments
2018
Net carrying amount - beginning of the year
Additions
Depreciation(a)
Reversal
Impairment
Write-off
Disposals
Currency translation differences
Changes in the scope of consolidation
Transfers
Other changes
Net carrying amount - end of the year
Gross carrying amount - end of the year
Provisions for depreciation and impairments
(a) Before capitalization of depreciation.
s
g
n
i
d
l
i
u
b
d
n
a
d
n
a
L
1,274
12
(60)
44
(47)
(1)
2
42
(48)
1,218
4,067
2,849
1,313
18
(65)
41
(61)
(2)
2
1
81
(54)
1,274
4,060
2,786
t
n
a
l
p
,
s
l
l
e
w
P
&
E
y
r
e
n
i
h
c
a
m
d
n
a
42,856
144
(6,435)
65
(659)
(3)
815
2,028
7,568
113
46,492
144,789
98,297
45,782
432
(6,012)
299
(477)
(12)
(400)
1,623
(4,388)
6,795
(786)
42,856
135,467
92,611
d
n
a
t
n
a
l
p
r
e
h
t
O
y
r
e
n
i
h
c
a
m
3,901
223
(537)
69
(500)
(5)
(1)
21
597
(136)
3,632
28,191
24,559
3,877
173
(529)
86
(73)
(1)
(9)
36
32
461
(152)
3,901
27,516
23,615
n
o
i
t
a
r
o
l
p
x
e
P
&
E
l
a
s
i
a
r
p
p
a
d
n
a
s
t
e
s
s
a
1,267
508
14
(216)
(22)
24
25
(42)
5
1,563
1,563
e
l
b
i
g
n
a
t
P
&
E
s
s
e
r
g
o
r
p
n
i
s
t
e
s
s
a
9,195
6,170
202
65
(669)
(49)
(80)
181
21
(7,526)
(98)
7,412
11,406
3,994
1,371
330
9,469
6,947
(66)
(32)
53
(58)
(294)
(37)
1,267
1,267
(548)
(4)
(198)
385
(474)
(6,501)
119
9,195
12,559
3,364
s
s
e
r
g
o
r
p
n
i
s
t
e
s
s
a
e
l
b
i
g
n
a
t
r
e
h
t
O
s
e
c
n
a
v
d
a
d
n
a
1,809
992
139
(537)
(6)
1
(639)
116
1,875
2,799
924
1,346
878
(117)
(1)
2
(1)
10
(542)
234
1,809
2,415
606
l
a
t
o
T
60,302
8,049
216
(7,032)
382
(2,412)
(270)
(113)
1,044
2,074
(48)
62,192
192,815
130,623
63,158
8,778
(6,606)
426
(1,276)
(84)
(639)
2,098
(4,877)
(676)
60,302
183,284
122,982
Capital expenditures included capitalized finance expenses of €93
million (€52 million in 2018) related to the Exploration & Production
segment for €71 million (€37 million in 2018). The interest rate used
for capitalizing finance expense ranged from 2.6% to 2.8% (2.3% to
2.4% at December 31, 2018).
Capital expenditures primarily related to the Exploration & Production
segment for €6,889 million (€7,757 million in 2018) and included the
consideration of €400 million paid for the acquisition of a proved and
unproved mineral interest in an already participated producing field in
the United States, an entry bonus in a property under development in
Algeria and the residual entry bonus in a concession in the United Arab
Emirates; therefore, part of those expenditures increased unproved
mineral properties.
More information is reported in note 35 – Segment information and
information by geographical area.
The main depreciation rates used were substantially unchanged from
the previous year and ranged as follows:
(%)
Buildings
Mineral exploration wells and plants
Refining and chemical plants
Gas pipelines and compression stations
Power plants
Other plant and machinery
Industrial and commercial equipment
Other assets
2 - 10
UOP
3 - 17
4 - 12
4 - 5
6 - 12
5 - 25
10 - 20
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019
178
The criteria adopted by Eni for determining impairment losses and
reversal is reported in note 14 – Impairment review of tangible and
intangible assets and right-of-use assets.
Foreign currency translation differences primarily related to subsidiaries
which utilize the US dollar as functional currency (€976 million).
Initial recognition and changes in estimates include the increase in the
asset retirement cost of Exploration & Production tangible assets due
to the decrease in the discount rate curve and new obligations recorded
during the year.
Transfers from E&P tangible assets in progress to E&P UOP wells, plant
and machinery related for €4,560 million to progress in the development
of reserves primarily in Egypt, Mexico, Libya, Ghana and Angola.
Changes in exploration and appraisal activities related to: (i) the
successful completion of exploration and appraisal activities at certain
suspended exploration wells and their transfer to tangible assets for
€46 million, primarily in Egypt and Angola; (ii) write-off of unsuccessful
exploration wells costs for €183 million mainly in Australia, Kazakhstan,
Pakistan, China and United Kingdom.
Exploration and appraisal activities related for €1,246 million to costs of
suspended exploration wells pending final determination and for €317
million to costs of exploration wells in progress at the end of the year.
Changes relating to suspended wells are showed:
(€ million)
Costs for exploratory wells suspended - beginning of the year
Increases for which is ongoing the determination of proved reserves
Amounts previously capitalized and expensed in the year
Reclassification to successful exploratory wells following the estimation of proved reserves
Disposals
Changes in the scope of consolidation
Reclassification to assets held for sale
Currency translation differences
Costs for exploratory wells suspended - end of the year
2019
1,101
368
(183)
(46)
(15)
21
1,246
2018
1,263
235
(61)
(297)
(6)
(58)
(24)
49
1,101
2017
1,684
451
(217)
(278)
(199)
(178)
1,263
The following information relates to the stratification of the suspended wells pending final determination (ageing):
Costs capitalized and suspended for exploratory well activity
- within 1 year
- between 1 and 3 years
- beyond 3 years
Costs capitalized for suspended wells
- fields including wells drilled over the last 12 months
- fields for which the delineation campaign is in progress
- fields including commercial discoveries that proceeds
to sanctioning
2019
2018
2017
(€ million)
(number of wells
in Eni’s interest)
(€ million)
(number of wells
in Eni’s interest)
(€ million)
(number of wells
in Eni’s interest)
185
171
890
1,246
185
556
505
1,246
7.7
6.4
26.4
40.5
7.7
11.3
21.5
40.5
111
87
903
1,101
111
217
773
1,101
7.0
2.9
24.2
34.1
7.0
4.7
22.4
34.1
222
241
800
1,263
148
261
854
1,263
8.0
3.9
21.4
33.3
5.9
4.7
22.7
33.3
Suspended wells costs awaiting a final investment decision amounted
to €505 million and included a significant amount relating to the
exploration costs incurred for the Mamba discovery in Mozambique's
offshore Area 4, for which the venture partners are completing the
activities for sanctioning the project. The other suspended costs refer
to initiatives ongoing in the main Countries of presence (Nigeria,
Angola, Congo and Egypt), none of which, however, represents an
individually significant amount.
Unproved mineral interests include the purchase price allocated to
unproved reserves following business combinations or acquisition of
individual properties. Unproved mineral interests were as follows:
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
179
(€ million)
2019
Book amount at the beginning of the year
Additions
Net (impairments) reversals
Reclassification to proved mineral interest
Currency translation differences
Book amount at the end of the year
2018
Book amount at the beginning of the year
Additions
Net (impairments) reversals
Reclassification to proved mineral interest
Other changes and currency translation differences
Book amount at the end of the year
o
g
n
o
C
a
i
r
e
g
i
N
769
921
(533)
17
253
1,162
26
(429)
(32)
42
769
18
939
825
56
40
921
n
a
t
s
i
n
e
m
k
r
u
T
77
65
(4)
1
139
A
S
U
103
97
(27)
(14)
3
162
a
i
r
e
g
l
A
77
135
(99)
2
115
192
99
105
(76)
(44)
5
77
4
103
(32)
4
77
b
a
r
A
d
e
t
i
n
U
d
e
t
a
r
i
m
E
502
23
10
535
487
15
502
l
a
t
o
T
2,478
256
(495)
(129)
52
2,162
2,390
592
(505)
(110)
111
2,478
t
p
y
g
E
29
1
(12)
1
19
7
23
(2)
1
29
Unproved mineral interests comprised a property denominated Oil
Prospecting License 245 (OPL 245), offshore Nigeria, with a net
book value of €874 million corresponding to the price paid in 2011
to the Nigerian Government to acquire a 50% interest in the property,
together with the partner Shell which acquired the remaining 50%. As
of December 31, 2019, the net book value of the property amounted to
€1,184 million, including capitalized exploration and pre-development
costs. The acquisition of OPL 245 is subject to judicial proceedings
in Italy and in Nigeria for alleged corruption and money laundering in
respect of the Resolution Agreement signed on April 29, 2011, relating
to the purchase of the license by Eni and Shell. Those proceedings
are disclosed in note 27 – Guarantees, Commitments and Risks.
The impairment test of the asset confirmed the book value also
considering a stress test assuming possible delays in the start of
development activities.
Accumulated provisions for impairments amounted to €18,226 million
(€16,471 million at December 31, 2018).
Property, plant and equipment include assets subject to leases for
€241 million.
At December 31, 2019, Eni pledged property, plant and equipment for
€24 million to guarantee payments of excise duties (same amount as
of December 31, 2018).
Government grants recorded as a decrease of property, plant and
equipment amounted to €112 million (€125 million at December 31, 2018).
Contractual commitments related to the purchase of property, plant
and equipment are disclosed in note 27 – Guarantees, commitments
and risks – Liquidity risk.
Property, plant and equipment under concession arrangements are
described in note 27 – Guarantees, commitments and risks – Assets
under concession arrangements.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019
180
12 | Right-of-use assets and lease liabilities
i
g
n
d
a
o
ffl
o
d
n
a
e
g
a
r
o
t
s
n
o
i
t
c
u
d
o
r
p
g
n
i
t
a
o
l
F
)
O
S
P
F
(
s
l
e
s
s
e
v
g
i
r
g
n
i
l
l
i
r
D
3,294
346
3,294
32
(240)
67
3,153
3,393
240
346
192
(224)
6
(7)
313
528
215
s
e
s
a
b
c
i
t
s
i
g
o
l
d
e
t
a
l
e
r
d
n
a
s
e
i
t
i
l
i
c
a
f
l
a
v
a
N
n
o
i
t
a
t
r
o
p
s
n
a
r
t
s
a
G
&
l
i
O
r
o
f
569
569
219
(272)
4
(23)
497
757
260
y
a
w
r
o
t
o
M
d
n
a
s
n
o
i
s
s
e
c
n
o
c
s
n
o
i
t
a
t
s
e
c
i
v
r
e
s
462
30
492
54
(61)
(13)
2
(14)
460
532
72
(€ million)
First adoption IFRS 16
Reclassifications
Reclassifications to assets held for sale
Net carrying amount at January 1, 2019
Additions
Depreciation(a)
Impairment losses
Currency translation differences
Other changes
Net carrying amount at December 31, 2019
Gross carrying amount
Provisions for depreciation and impairment
n
o
i
t
u
b
i
r
t
s
i
d
s
a
G
&
l
i
O
s
e
i
t
i
l
i
c
a
f
7
s
g
n
d
i
l
i
u
b
e
c
ffi
O
720
s
e
l
c
i
h
e
V
43
7
1
(1)
(1)
6
7
1
720
108
(115)
3
(9)
707
806
99
43
22
(23)
(10)
32
54
22
r
e
h
t
O
215
16
(13)
218
56
(63)
(28)
3
(5)
181
274
93
l
a
t
o
T
5,656
46
(13)
5,689
684
(999)
(41)
85
(69)
5,349
6,351
1,002
(a) Before the capitalization of depreciation for tangible and intangible assets.
The first application of IFRS 16 is disclosed in note 3 – Changes in
accounting policies.
Right-of-use assets (RoU) related: (i) for €3,895 million to the
Exploration & Production segment and mainly comprised the operating
leases of certain FPSO vessels hired in connection with operations
at offshore development projects in Ghana (OCTP) and Angola (Block
15/06 West and East hub) with expiry date between 10 and 18 years
including a renewal option and in addition the lease component of
long-term leases of offshore rigs; (ii) for €512 million to the Refining &
Marketing and Chemicals segment relating to motorway concessions,
land leases, leases of service stations for the sale of oil products
and the car fleet dedicated to the car sharing business; (iii) for
€365 million to the Gas & Power segment relating to the leasing of
naval vessels for shipping activities and logistics structures for gas
distribution; (iv) for €577 million to the Corporate and Other activities
segment mainly regarding property rental contracts.
The main leasing contracts signed for which the asset is not yet
available concern : (i) a contract with a nominal value of €2.1 billion
relating to an FPSO vessel that will be deployed for the development of
Area 1 in Mexico. The asset is expected to enter under the Group's control
and be accounted as RoU in 2021, expiring in 2040; (ii) a contract with a
nominal value of €438 million relating to leasing of offices buildings with
an expiry date of 20 years with an extension option of 6 years.
The main future cash outflows potentially due not reflected in the
measurements of lease liabilities related to: (i) options for the extension
or termination of lease for office buildings of €297 million; (ii) service
stations for the sale of oil products of €155 million; (iii) other extension
options related to concessions of land for €60 million and ancillary assets
in the upstream business for €84 million.
Liabilities for leased assets were as follows:
(€ million)
First adoption IFRS 16
Reclassifications
Reclassifications to liabilities directly associated with assets held for sale
Carrying amount at January 1, 2019
Additions
Decreases
Currency translation differences
Other changes
Carrying amount at December 31, 2019
f
o
n
o
i
t
r
o
p
t
n
e
r
r
u
C
e
s
a
e
l
m
r
e
t
-
g
n
o
l
s
e
i
t
i
l
i
b
a
i
l
665
132
(3)
794
(875)
10
960
889
e
s
a
e
l
m
r
e
t
g
n
o
L
s
e
i
t
i
l
i
b
a
i
l
4,991
36
(10)
5,017
668
(2)
77
(1,001)
4,759
l
a
t
o
T
5,656
168
(13)
5,811
668
(877)
87
(41)
5,648
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
181
Lease liabilities related for €1,976 million to the portion of the
liabilities attributable to the joint operators in Eni-led projects which
will be recovered through the mechanism of the cash calls.
Total cash outflows for leases consisted of the following: (i) cash
payments for the principal portion of the lease liability for €877
million; (ii) cash payments for the interest portion of €347 million;
(iii) prepayment RoU for leased assets for €16 million.
The amounts recognised in the profit and loss account consist of the
following:
(€ million)
Other income and revenues
Income from remeasurement of lease liabilitiy
Purchases, services and other
Short-term leases
Low-value leases
Variable lease payments not included in the measurement of lease liabilities
Capitalised direct cost associated with self-constructed assets - tangible assets
Depreciation and impairments
Depreciation of RoU leased assets
Capitalised direct cost associated with self-constructed assets - tangible assets
Impairment losses of RoU leased assets
Finance income (expense) from leases
Interests on lease liabilities
Capitalised finance expense of ROU leased assets - tangible assets
Net currency translation differences on lease liabilities
2019
6
6
115
39
16
(2)
168
999
(210)
41
830
(378)
17
(6)
(367)
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019
182
13 | Intangible assets
(€ million)
2019
Net carrying amount - beginning of the year
Additions
Amortization
Impairments
Write-off
Currency translation differences
Other changes
Net carrying amount at the end of the year
Gross carrying amount at the end of the year
Provisions for amortization and impairment
2018
Net carrying amount - beginning of the year
Changes in accounting policies (IFRS 15)
Net carrying amount restated - beginning of the year
Additions
Amortization
Impairments
Write-off
Currency translation differences
Changes in the scope of consolidation
Other changes
Net carrying amount at the end of the year
Gross carrying amount at the end of the year
Provisions for amortization and impairment
s
t
h
g
i
r
n
o
i
t
a
r
o
l
p
x
E
1,081
78
(81)
(19)
(28)
18
(18)
1,031
1,748
717
995
995
133
(71)
(15)
39
1,081
1,686
605
s
t
n
e
t
a
p
l
a
i
r
t
s
u
d
n
I
l
a
u
t
c
e
l
l
e
t
n
i
d
n
a
s
t
h
g
i
r
y
t
r
e
p
o
r
p
221
23
(93)
(1)
45
195
1,597
1,402
240
240
28
(87)
40
221
1,534
1,313
e
l
b
i
g
n
a
t
n
i
r
e
h
t
O
s
t
e
s
s
a
584
210
(117)
(72)
(1)
1
(37)
568
4,373
3,805
486
87
573
180
(226)
(16)
(1)
74
584
4,188
3,604
s
t
e
s
s
a
e
l
b
i
g
n
a
t
n
I
l
u
f
e
s
u
e
t
i
n
fi
h
t
i
w
s
e
v
i
l
1,886
311
(291)
(91)
(30)
19
(10)
1,794
7,718
5,924
1,721
87
1,808
341
(384)
(16)
(16)
39
74
40
1,886
7,408
5,522
l
l
i
w
d
o
o
G
1,284
(26)
3
4
1,265
1,204
1,204
8
46
26
1,284
l
a
t
o
T
3,170
311
(291)
(117)
(30)
22
(6)
3,059
2,925
87
3,012
341
(384)
(16)
(16)
47
120
66
3,170
Exploration rights comprised the residual book value of license
and leasehold property acquisition costs relating to areas with
proved reserves, which are amortized based on UOP criteria and
are regularly reviewed for impairment. Furthermore, they include
the cost of unproved areas which are suspended pending a final
determination of the success of the exploration activity or until
management confirms its commitment to the initiative. Additions for
the year related to signature bonuses paid for the acquisition of new
exploration acreage mainly in United Arab Emirates, Mozambique,
Mexico and Indonesia.
The breakdown of exploration rights by type of asset was as follows:
(€ million)
Proved licence and leasehold property acquisition costs
Unproved licence and leasehold property acquisition costs
Other mineral interests
December 31, 2019
291
709
31
1,031
December 31, 2018
357
684
40
1,081
Industrial patents and intellectual property rights mainly regarded the
acquisition and internal development of software and rights for the use
of production processes and software.
Other intangible assets comprised: (i) customer acquisition costs
relating to the retail gas business for €226 million (€166 million at
December 31, 2018); (ii) concessions, licenses, trademarks and
similar items for €102 million (€151 million at December 31, 2018)
comprised transmission rights for natural gas imported from Algeria
of €30 million (€27 million at December 31, 2018); (iii) capital
expenditures in progress on natural gas pipelines for which Eni has
acquired transport rights for €78 million (same amount at December
31, 2018).
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
The main amortization rates used were substantially unchanged from the previous year and ranged as follows:
(%)
Exploration rights
Transport rights of natural gas
Other concessions, licenses, trademarks and similar items
Service concession arrangements
Capitalized costs for customer acquisition
Other intangible assets
183
UOP - 33
3
3 - 33
20 - 33
25 - 33
4 - 20
The carrying amount of goodwill at the end of the year amounted €2,454 million, net of cumulative impairments charges. The breakdown by
segment is provided below:
(€ million)
Gas & Power
Exploration & Production
Refining & Marketing and Chemicals
Other activities
December 31, 2019
981
190
93
1
1,265
December 31, 2018
977
187
119
1
1,284
An impairment loss the entire of allocated goodwill was recorded
by the Chemical business line in relation to activities concerning
the development, industrialization, licensing of bio-chemical
technologies and processes based on the use of renewable sources.
An increase in goodwill was recorded in connection with the
allocation of the acquisition cost of the company SEA SpA, which
engages in providing services and solutions for energy efficiency in
the residential and industrial segments.
Goodwill acquired through business combinations has been
allocated to the CGUs that are expected to benefit from the synergies
of the acquisition.
The amount of goodwill outstanding at the reporting date mainly
related to the Gas & Power segment.
A breakdown is disclosed below:
(€ million)
Domestic gas market
Foreign gas market
December 31, 2019
839
142
981
December 31, 2018
835
142
977
Goodwill allocated to the CGU domestic gas market was recognized upon
the buy-out of the former Italgas SpA minorities in 2003 through a public
offering (€706 million). The acquired entity engaged in the retail sale of
gas to the residential sector and middle and small-sized businesses in
Italy. In addition, further goodwill amounts have been allocated over the
years following business combinations with small, local companies selling
gas to residential customers in focused territorial reach and municipalities
synergic to Eni’s activities. The impairment review performed at the
balance sheet date confirmed the recoverability of the carrying amount of
this CGU, including the allocated goodwill.
In assessing the recoverability of the carrying amount of the CGU
domestic gas market, including the allocated portion of goodwill,
management determined the value in use of the CGU considering the
sales margin exclusively of the retail market (excluding margins on
sales to wholesalers, industrial and power generation customers).
The assessment was performed considering the cash flows of the
four-year plan approved by management and incorporating a terminal
value calculated as perpetuity of the last year of the plan by assuming
a nominal long-term growth rate equal to zero, unchanged from the
previous reporting period. These cash flows were discounted by using
the post-tax WACC adjusted considering the specific country risk of
5.3% for Italy. Post-tax cash flows and discount rates were adopted
as they resulted in an assessment that substantially approximated a
pre-tax assessment.
There are no realistic hypotheses of changes in the discount rate, growth
rate, profitability or volumes that would lead to zeroing the headroom
amounting to €1,701 million of the value in use of the Italian Market CGU
with respect to its book value, including the goodwill.
Goodwill allocated to the CGU European gas market related for €95 million
to Eni Gas & Power France SA (former Altergaz SA) operating in France
and for €45 million to the acquisition in 2018 of the residual 51% interest
in Gas Supply Company Thessaloniki-Thessalia SA operating in Greece,
previously participated with a 49% of the share capital. The impairment
review performed at the balance sheet date by using a method similar to
the Domestic gas market CGU confirmed the recoverability of the carrying
amount of these gas market CGUs, including any allocated goodwill, by
using a post-tax WACC adjusted considering a country risk for France of
5.9%, and 6.2% for Greece.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019
184
14 | Impairment review of tangible and intangible assets and right-of-use assets
In assessing whether impairment is required, the carrying amounts
of the assets are compared with their recoverable amounts. The
recoverable amount is the higher between an asset’s fair value
less costs to sell and its value-in-use. In the event of an asset’s
impairment being reversed, the reversal may not raise the carrying
amount above the value it would have stood at taking into account
depreciation, if no impairment had originally been recognized.
Impairment losses of goodwill cannot be reversed.
Given the nature of Eni’s activities, information on asset fair value is
usually difficult to obtain unless negotiations with a potential buyer
are ongoing. Therefore, the recoverability is verified by estimating
assets’ values-in-use. The valuation is carried out for individual
assets or for the smallest identifiable group of assets that generates
cash inflows that are largely independent from the cash inflows
from other assets, or groups of assets (cash generating unit – CGU).
The Group has identified the following CGUs: (i) in the Exploration
& Production segment, individual oilfields or pools of oilfields when
technical, economic or contractual features make underlying cash
flows interdependent; (ii) in the Gas & Power segment, the CGUs to
which goodwill arisen from business combinations was allocated
and costs for customer acquisition (Italian retail market and other
foreign markets), electric power plants, international pipelines and
other minor activities; (iii) in the Refining & Marketing business line,
refining plants, and assets related to distribution channels grouped
by Country of operations and type of network (retail outlets located
along ordinary routes and high-ways, wholesale facilities); and (iv) in
the Chemical business five lines of activities have been identified as
autonomous CGUs: intermediates, polyethylene, styrenes, elastomers
and biotech activities.
As of 2019, following the application of IFRS 16, the book values of the
identified CGUs include the right of use assets (RoU), associated to
plants and equipment hired in connection with operations at specific
CGUs operations. Because they are instrumental to specific CGUs
operation, those RoU assets lack the requisites to be evaluated as
autonomous CGUs. The CGUs’ cash flows to which the RoUs have been
allocated, exclude lease liability repayments according to the unlevered
valuation methodology used for capital projects. Rather, a small number
of RoU not allocated to CGU are considered corporate assets, whose
recoverability depends on the whole of the Company’s CGUs.
The value-in-use is calculated by discounting the estimated future
cash flows deriving from the continuing use of the CGUs and, if
significant and reasonably determinable, the cash flows deriving
from disposal at the end of their useful lives. Cash flows are
determined based on the best information available at the time of
the assessment. Cash flow projections for the first four years of each
CGU evaluation are extracted from the Company’s four-year plan
adopted by the top management. The plan includes data points on
expected Oil & Gas production volumes, reserves, sales volumes,
capital expenditure, operating costs and margins and industrial and
marketing set-up, as well as trends on the main macroeconomic
variables, including inflation, nominal interest rates and exchange
rates. The estimation of CGUs’ terminal values is based on cash flow
projections beyond the four-year plan horizon, which are estimated
based on management’s long-term assumptions regarding the main
macroeconomic variables (inflation rates, commodity prices, etc.)
and considering the expected useful lives of the Company’s CGUs
and certain assumptions regarding future trends in revenues and
costs. In the case of the Oil & Gas CGUs, management assumed the
residual life of the reserves considering the expected production rates
and the associated projections of operating costs and development
expenditures. The CGUs of Refining & Marketing, Chemicals and Gas
& Power, with a definite useful life, (i.e. power plants) are evaluated
based on the plant economic and technical life and the associated,
normalized projections of operating costs and expenditures to
support plant efficiency. The CGUs of the gas market business to
which goodwill has been allocated are evaluated based on the
perpetuity method of the last year-plan result assuming nominal
growth rates equal to 0%. In the forecast of the operating expenses
are considered expected costs to be incurred in compliance to the
so-called CO2 Emission Trading Scheme applicable to CGUs operating
within the EU economic space. In projecting future commodity prices,
management assumed the price scenario adopted for the economic
and financial projections of the Company’s four-year industrial plans
and for the assessment of capital projects returns.
The Company’s price scenario is approved by the Board of Directors
and is based on internal assumptions about future trends in the
fundamentals of demand and supply of crude oil and other commodities
as benchmarked against the market consensus forecasts and on
forward prices of commodities for future delivery in case the level of
liquidity and reliability of future contracts is deemed fair.
The oil market continues to be affected by weak fundamentals
against the backdrop of an unabated supply glut, fueled by continuing
grow in US tight oil output and a seemingly fading commitment
on part of the oil producers of the OPEC+ agreement at supporting
crude oil prices going forward. The market is also weighed down by
uncertainties about the strength of the global economic recovery,
exposed to a wide range of systemic risks, including geopolitical
risks, any possible development in the trade dispute between USA
and China, the relationship between the EU and the UK post Brexit
and the risks of pandemic diseases. Eni’s management forecast a
gradual rebalancing of global supplies and demand for crude oil over
the medium term, under the assumptions of moderate economic
growth and taking into account the stricter capital discipline adopted
by major oil companies designed to curtail growth plans to boost
shareholders’ returns and lately a shift in the financial approach
retained by the US independent producers which have de-emphasized
growth to preserve the free cash flow. Based on these considerations
and taking into account the forecasts made by specialized
observatories and investment banks, management has retained its
assumption of a long-term Brent crude oil price of 70 $/bbl in real
terms 2022, substantially in line with the assumption made in the
annual report 2018.
The oversupply condition is even more severe in the gas market
due to excess production of associated gas in the USA and to the
ramp-up of several liquefaction projects which have significantly
increased global supplies of LNG at a time when the greatest
consuming countries have slowed down (China, South Korea and
Japan). Management expect gas prices to rebalance in the medium
term considering an anticipated recovery of the Asian economies
and also considering an ongoing switch from coal to gas in the power
generation in Europe. Overall, price assumptions for the main gas
benchmarks in Europe have been retained at the same level as the
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 185
previous planning projections, whilst gas prices assumptions have
been revised downward for the reference Henry Hub gas prices in USA
due to structural headwinds.
Having retained management’s long-term assumptions for crude oil
prices unchanged from the previous financial statements, the net
impairment indicators at the Company’s oil&gas assets were mainly
driven by downward reserves revisions and a lowered operating
performance.
Furthermore, management is forecasting unchanged spreads for
natural gas between the selling prices at Eni’s reference market, Italy,
and the spot prices at continental hub to which the gas procurement
costs of our long-term contracts are indexed. This latter assumption
excludes any evidence of impairment indicator in relation to the G&P
fixed assets (particularly the goodwill recorded in the retail segment).
The Company’s downstream businesses of the refining and the
petrochemicals sectors are currently in a down-cycle due to weak
end-demands, excess production capacity and oversupplies and
continuing competitive pressures from overseas operators who can
leverage better cost positions and scale economies (for example
Middle East refiners and the ethane-based cracking of US chemicals
producers), while environmental issues are expected to negatively
affect consumption and profitability of gasoil and single-use plastics.
Operating costs for emission allowances as part of the European
Emission Scheme are also forecast to increase. Furthermore, Eni’s
complex refineries have been negatively affected by narrowing price
differentials between sour crudes with high sulfur content and the
light benchmark Brent crude, thus impairing the cost-advantage of
complex refineries of processing low-quality crudes that under normal
market conditions trade at a discount vs. the Brent. Due to those
structural weaknesses, management has reduced the profitability
outlook of its refineries and petrochemicals plants.
Management tested for impairment the totality of the Group’s fixed
assets as provided by the Company’s internal guidelines.
Values-in-use is estimated by discounting post-tax cash flows at a
rate, which corresponds for the Exploration & Production segment
and Refining & Marketing business line to the Company’s weighted
average cost of capital (WACC) net of specific risk factors attributable
to the Gas & Power segment and the Chemical business line, the
WACC of which is assessed on a stand-alone basis. Then the discount
rates are adjusted to factor in risks specific to each Country of activity
(adjusted post-tax WACC). Post-tax cash flows and discount rates
were adopted as they resulted in an assessment that substantially
approximated a pre-tax assessment.
In 2019 the weighted-average cost of capital (WACC) to the Group
increased marginally from 7.3% in 2018 to 7.4%. Based on our
estimation the cost of equity has significantly appreciated driven
by a sharp decline in government bond yields in 2019 that lifted the
so-called equity risk premium, or the excess return for equities over
a risk-free rate of return such as yields on treasuries of benchmark
Countries like USA and Germany and a step-up in the equity risk
premium applied by financial markets to the Oil & Gas sector
reflecting recent underperformance of the sector and uncertainties
over future returns considering the structural decline in hydrocarbons
prices and the risks associated with the energy transition. However,
this impact has been mitigated by a higher leverage following the
adoption of the accounting standard IFRS 16 which increased the total
finance debt recorded in the balance sheet and by this way reduced
the increase in the weighted average cost of capital to the Group due
to the higher equity risk.
Finally, a weighted-average premium for the country risk is added
to the cost of equity; the weighting factor is the amount of invested
capital in each Country of operations. Calculation of country-specific
WACC for each Country is obtained by adjusting the Group WACC by the
difference between the specific risk premium applicable to a given
Country and the average country risk premium of the Group portfolio.
Based on those assumptions, the existence of impairment indicators
and estimates of discount rates, management recorded the following
impairment losses: (i) in the Exploration & Production segment
the Company recorded impairment losses before taxes for €1,217
million driven by downward reserve revisions and lowered future
production rates mainly at properties in Congo (Wacc at 7.6%), Italy
(Wacc at 6.4%) and USA (Wacc at 6.5%), in this latter Country upward
estimates of operating costs and expenditures were projected, as well
as a loss on the disposal of a property in Ecuador. In the case of an
impairment loss higher than €100 million post-tax, a post-tax WACC
of 6.4% was applied, corresponding to pre-tax rate of 6.9%; (ii) in the
Refining & Marketing business line impairment losses of €819 million
were recorded, with the largest amount relating to the Sannazzaro
refinery for €684 million driven by the above mentioned revised
profitability outlook and also in connection to higher projected costs
for CO2 emissions; the remaining amount related to the investments
of the year for compliance and stay-in-business made at CGUs fully
impaired in prior years for which profitability expectations have
remained unchanged from the previous-year impairment review. In
the case of an impairment loss higher than €100 million post-tax, a
post-tax WACC of 6.6% was applied, corresponding to pre-tax rate of
7.1%; (iii) in the Chemicals business impairment losses amounted
to €103 million driven by the deteriorated market outlook described
above; and (iv) in the G&P segment, €37 million of impairment
losses were recorded at power generation plants in connection to a
downward revision to the outlook for electricity margins due to higher
competition and overcapacity.
Furthermore, management assessed the recoverability of the
expected costs associated with the Company’s plans to ramp up the
participation in projects for forestry conservation and protection
from degradation. Those projects which have been started in 2019
envisage the purchase of carbon credits certified in accordance with
generally accepted international standards. Management projects
to build in future years a portfolio of forestry projects intended to
allow the Company to offset the net residual “Scope 1 and 2” carbon
emissions of the E&P business calculated on equity production for
the achievement of the carbon neutrality of the business from 2030
onwards. Those costs are considered part of the operating expenses
of the E&P business and their recoverability has been evaluated
in relation to the CGU E&P segment as a whole. When including
those costs extrapolated along the reserves residual life in the
determination of the value-in-use of the E&P segment, a 2% reduction
in the headroom of the segment is observed.
Ultimately, under management’s assumptions for a long-term Brent
price at 70 $/bbl (real terms 2022), which has remained unchanged
for the last few years, and at a reference price for the Italian spot gas
benchmark of 7.8 $/Mbtu, Eni’s Oil & Gas properties have exhibited a
substantial resilience of their carrying amounts, as highlighted by the
trend in the recognition of impairment losses in the last three years.
In 2017 we recorded a net reversal of €158 million and in 2018 we
recorded net impairment losses of €726 million. Impairment losses in
those three years have been driven mainly by asset-specific issues,
which were acquired during a historic phase of suspected peak
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019 186
supply, and in relation to certain complex operating environments.
However, considered the following trends of the sector: the increased
volatility of crude oil prices which have been increasingly exposed to
macro and global risks; the continued oversupply in the oil markets
which has determined a reset in hydrocarbons realized prices and
cash flows of oil companies; growing uncertainty about long-term
evolution of the global oil demand in light of the rising commitment
on part of the international community at fighting climate change and
speeding up the pace of the energy transition, the increase in energy
alternatives to fossil fuels and changing consumers’ preferences,
management has evaluated the recoverability of the book values of
Eni’s Oil & Gas properties at different stress-test scenarios, including
the risk of stranded assets. Particularly, under the toughest of the
assumptions at a flat long-term Brent price of 50 $/bbl and at a
flat Italian gas price of 5 $/Mbtu, management is estimating that
approximately 85% of the Company’s proven and probable/possible
reserves (risked at 70% and 30% respectively) will be produced within
2035 realizing 94% of the overall net present value in the same period.
The net present value of those production volumes, valued under the
most conservative of the scenarios considered, is substantially aligned
with the book values of the net fixed assets of Eni’s Oil & Gas properties,
including Eni’s share of the fixed assets of our joint ventures like Vår
Energi AS, and including in the calculation the expected cash outflows
committed to the Company’s forestry projects.
15 | Investments
EQUITY-ACCOUNTED INVESTMENTS
d
e
l
l
o
r
t
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c
s
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e
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i
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t
s
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n
I
d
e
t
a
d
i
l
o
s
n
o
c
n
u
i
n
E
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b
2019
s
e
r
u
t
n
e
v
t
n
i
o
J
s
e
t
a
i
c
o
s
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A
l
a
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e
l
l
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r
t
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t
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t
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e
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t
a
d
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l
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s
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n
u
i
n
E
y
b
n
i
s
t
n
e
m
t
s
e
v
n
I
95
5,497
1,452
7,044
116
22
5,519
76
80
(157)
(1,073)
67
80
4,592
95
6
(5)
6
(10)
(4)
1
2
(5)
86
1,452
2,910
(17)
75
(17)
(61)
17
(2)
4,357
22
7,066
2,992
(22)
161
(184)
(1,138)
1
86
73
9,035
116
(33)
8
(5)
(6)
2
13
95
2018
s
e
r
u
t
n
e
v
t
n
o
J
i
2,332
(34)
2,298
28
(3)
16
(415)
(19)
3,448
25
119
5,497
s
e
t
a
i
c
o
s
s
A
1,063
(3)
1,060
92
(115)
385
(10)
(25)
54
11
1,452
l
a
t
o
T
3,511
(37)
3,474
120
(151)
409
(430)
(50)
3,448
81
143
7,044
(€ million)
Carrying amount - beginning of the year
Changes in accounting policies (IFRS 9 and 15)
Changes in accounting policies (IAS 28)
Carrying amount restated - beginning of the year
Additions and subscriptions
Divestments and reimbursements
Share of profit of equity-accounted investments
Share of loss of equity-accounted investments
Deduction for dividends
Change in the scope of consolidation
Currency translation differences
Other changes
Carrying amount - end of the year
In 2019 additions and subscriptions related to: (i) a 20% equity interest in
Abu Dhabi Oil Refining Co (Takreer), UAE acquired for a cash consideration
of €2,896 million. The investee operates three refineries in Ruwais
(Ruwais East and Ruwais West) and Abu Dhabi, with a refining capacity
in excess of 900 kbbl per day. With this transaction, Eni enters the UAE
downstream sector and increases its global refining capacity by 35%, in
line with the Company’s strategy of making Eni’s overall portfolio more
geographically diversified and more balanced along the value chain; (ii)
a capital contribution of €39 million made to Lotte Versalis Elastomers Co
Ltd, joint venture operating in production of elastomers in South Korea.
Share of profit of equity-accounted investments included a gain of €49
million related to Vår Energi AS and of €47 million to Angola LNG Ltd.
The accounting under the equity method of Saipem SpA resulted
in a gain of €4 million. Considering the volatility of the Saipem
shares and the ongoing uncertainties surrounding a recovery in
the investing cycle of oil companies and competitive pressure
in the Engineering & Construction segment, management
performed an impairment review of the investment to assess its
recoverability based on an internal financial model of future cash
flows of Saipem. Inputs to that model were estimated based on
financial projections made by the sell-side analysts who cover the
Saipem shares, publicly available data on Saipem and the observed
historical correlation which link the Saipem turnover to crude oil
prices and spending in capital projects made by oil companies. This
review supported the book value of the investment.
Share of losses of equity-accounted investments included a loss of €90
million accounted at the joint venture Cardón IV SA (Eni’s interest 50%)
which is operating the Perla gas field affected by the slowdown in the gas
supplies to the buyer PDVSA due to a deteriorated operating environment.
Deduction for dividends related for 1,057 million to Vår Energi AS.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
Net carrying amount related to the following companies:
(€ million)
Investments in unconsolidated entities controlled by Eni
Eni BTC Ltd
Other(*)
Joint ventures
Vår Energi AS
Saipem SpA
Unión Fenosa Gas SA
Cardón IV SA
Gas Distribution Company of Thessaloniki - Thessaly SA
Lotte Versalis Elastomers Co Ltd
PetroJunín SA
AET - Raffineriebeteiligungsgesellschaft mbH
Other(*)
Associates
Abu Dhabi Oil Refining Co (Takreer)
Angola LNG Ltd
Coral FLNG SA
Novamont SpA
United Gas Derivatives Co
Commonwealth Fusion Systems Llc(a)
Other(*)
(*) Each individual amount included herein was lower than €25 million.
(a) The ownership cannot be determined.
187
December 31, 2019
December 31, 2018
i
g
n
y
r
r
a
c
t
e
N
t
n
u
o
m
a
30
56
86
2,518
1,250
326
148
139
74
53
35
49
4,592
2,829
1,159
102
71
69
37
90
4,357
9,035
t
n
e
m
t
s
e
v
n
i
e
h
t
f
o
%
100.00
69.60
30.99
50.00
50.00
49.00
50.00
40.00
33.33
20.00
13.60
25.00
25.00
33.33
i
g
n
y
r
r
a
c
t
e
N
t
n
u
o
m
a
31
64
95
3,498
1,228
335
98
137
75
47
32
47
5,497
1,106
102
67
62
42
73
1,452
7,044
t
n
e
m
t
s
e
v
n
i
e
h
t
f
o
%
100.00
69.60
30.99
50.00
50.00
49.00
50.00
40.00
33.33
13.60
25.00
25.00
33.33
As of December 31, 2019, the book value of investments included Vår
Energi SA which was established at the end of 2018 following the merger
between the former Eni subsidiary Eni Norge AS and Point Resources
AS for maximizing synergies in the development of hydrocarbon
reserves in Norway through the sharing of assets and know-how. The
decrease of €980 million compared to the opening balance was due
to the distribution of dividends classified as part of the cash flow from
operating activities considering that Vår Energi SA is an investment
integrated in the industrial plans and the upstream growth strategy of
Eni. This decrease was partially absorbed by Eni's share of profit.
Results of equity-accounted investments by segment are disclosed in
note 35 – Segment information and information by geographical area.
The carrying amounts of equity-accounted investments included
differences between the purchase price of acquired interests and
their underlying book value of net assets amounting to €72 million,
related to Novamont SpA for €43 million and Unión Fenosa Gas SA for
€29 million. These surpluses were driven by the long-term profitability
outlook of the acquired companies at the time of the acquisition.
As of December 31, 2019, the market value of the investments listed in
regulated stock markets was as follows:
Number of shares held
% of the investment
Share price (€)
Market value (€ million)
Book value (€ million)
Additional information is included in note 37 – Other information about investments.
Saipem SpA
308,767,968
30.99
4.356
1,345
1,250
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019
188
OTHER INVESTMENTS
(€ million)
Carrying amount - beginning of the year
Changes in accounting policies (IFRS 9)
Carrying amount restated - beginning of the year
Additions and subscriptions
Change in the fair value
Divestments and reimbursements
Currency translation differences
Other changes
Carrying amount - end of the year
2019
919
919
11
(3)
(12)
15
(1)
929
2018
219
681
900
5
15
(22)
31
(10)
919
The fair value of the main non-controlling interests in non-listed investees
on regulated markets, classified within level 3 of the fair value hierarchy,
was estimated based on a methodology that combines future expected
earnings and the sum-of-the-parts methodology (so-called residual
income approach) and takes into account, inter alia, the following inputs:
(i) expected results, as a gauge of the future profitability of the investees,
derived from the business plans, but adjusted, where appropriate, to
include the assumptions that market participants would incorporate; (ii)
the cost of capital, adjusted to include the risk premium of the specific
Country in which each investee operates. A stress test based on a 1%
change in the cost of capital considered in the valuation did not produce
significant changes at the fair value evaluation.
Dividend income from these investments is disclosed in note 31 – Income
(expense) from investments.
The investment book value as of December 31, 2019 primarily related
to Nigeria LNG Ltd for €657 million (€651 million at December 31, 2018)
and Saudi European Petrochemical Co “IBN ZAHR” for €146 million (€144
million at December 31, 2018).
16 | Other financial assets
(€ million)
Long-term financing receivables held for operating purposes
Short-term financing receivables held for operating purposes
Financing receivables held for non-operating purposes
Securities held for operating purposes
Financing receivables are stated net of allowance for doubtful accounts as follows:
384
Non-current
1,119
December 31, 2019
Current
60
37
97
287
384
1,119
1,119
55
1,174
Non-current
1,189
December 31, 2018
Current
61
51
112
188
300
1,189
1,189
64
1,253
300
(€ million)
Carrying amount at the beginning of the year
Additions
Deductions
Currency translation differences
Other changes
Carrying amount at the end of the year
2019
430
11
(88)
7
19
379
2018
730
279
(596)
17
430
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
189
Financing receivables held for operating purposes related principally
to funds provided to joint ventures and associates in the Exploration &
Production segment (€1,041 million) and the Gas & Power segment
(€49 million) to execute capital projects of interest to Eni. These
receivables are expression of long-term interests in the initiatives
funded. The greatest exposure is towards the joint venture Cardón IV SA
(Eni’s interest 50%) in Venezuela, which is currently operating the Perla
offshore gas field, for €563 million at December 31, 2019 (€705 million
at December 31, 2018).
Financing receivables held for operating purposes due beyond five years
amounted to €1,018 million (€1,088 million at December 31, 2018).
The fair value of non-current financing receivables held for operating
purposes of €1,119 million has been estimated based on the present
value of expected future cash flows discounted at rates ranging from
-0.3% to 2.0% (-0.2% and 2.9% at December 31, 2018).
The recoverability of the financial loan granted to the joint venture
Cardón IV SA to fund the development projects carried out by the venture
was assessed based on the future, expected cash flows of the industrial
project. This cash flows are exposed to a counterparty risk given the
difficult financial condition of Venezuela and of the national oil company,
PDVSA, and to the complexity of the local operating environment.
To factor in those risks in assessing the recoverability of the financing,
the future cash flows of the project have been adjusted to price
possible difficulties in converting future gas sales into cash, essentially
assuming a deferral in the time of revenues collection. This schedule was
estimated on the basis of a study on empirical evidence relating to the
average recovery rates obtained by creditors in the context of sovereign
defaults, adjusted to reflect the strategic role of the energy sector to
local economy. Those risked cash flows have been then discounted to a
risk-adjusted WACC which incorporates the deteriorated local operating
environment. This recoverability assessment confirmed the book value
of the financial receivable. The same method was used to estimate the
recoverable amount of the overdue trade receivables for gas supplies to
the state-owned company PDVSA. In 2019, the percentages of the gas
revenues collected by the joint venture were in line with the estimates
adopted in assessing the loss-given-default applied in the evaluation
recoverability performed in 2018; therefore, no adjustment was
necessary to the estimation of the percentage of recoverability of these
receivables.
The recoverability of other long-term financial assets was assessed by
considering the expected probability default in the next twelve months
only, as the creditworthiness suffered no significant deterioration in the
reporting period.
Financing receivables held for non-operating purposes related to bank
deposits with the purpose to invest cash surpluses and restricted
deposits in escrow to guarantee transactions on derivative contracts.
Financing receivables held for operating purposes were denominated in
euro and US dollar for €370 million and €1,112 million, respectively.
Securities held for operating purposes related to listed bonds issued by
sovereign States.
Securities for €20 million (same amount at December 31, 2018) were
pledged as guarantee of the deposit for gas cylinders as provided for by
the Italian law.
The following table analyses securities per issuing entity:
t
s
o
c
d
e
z
i
t
r
o
m
A
)
n
o
i
l
l
i
m
€
(
24
23
5
3
55
e
u
l
a
v
l
i
a
n
m
o
N
)
n
o
i
l
l
i
m
€
(
24
23
5
3
55
e
u
l
a
v
r
i
a
F
)
n
o
i
l
l
i
m
€
(
25
23
5
3
56
f
o
e
t
a
r
l
i
a
n
m
o
N
n
r
u
t
e
r
%
e
t
a
d
y
t
i
r
u
t
a
M
'
s
y
d
o
o
M
-
g
n
i
t
a
R
P
&
S
-
g
n
i
t
a
R
from 0.20 to 4.75
from 0.05 to 4.20
from 2020 to 2025
from 2020 to 2024
Baa3
from Aa3 to Baa1
BBB
from AA to A-
from 2020 to 2022
2022
Baa3
Baa3
BBB
BBB
Sovereign States
Fixed rate bonds
Italy
Others(*)
Floating rate bonds
Italy
Others
Total sovereign States
(*) Amounts included herein are lower than €10 million.
All securities have maturity within five years.
The fair value of securities was derived from quoted market prices.
Receivables with related parties are described in note 36 –
Transactions with related parties.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019
190
17 | Trade and other payables
The following are the effects of the application of IFRS 16:
(€ million)
Carrying amount at December 31, 2018
Changes in accounting policies (IFRS 16)
Carrying amount at January 1, 2019
Down payments
and advances from
joint ventures
in exploration
and production
activities
207
Other payables
4,895
207
4,895
Trade payables
11,645
(128)
11,517
Total trade and
other payables
16,747
(128)
16,619
The first application of IFRS 16 is disclosed in note 3 – Changes in
accounting policies.
The breakdown of trade and other payables is the following:
(€ million)
Trade payables
Down payments and advances from joint ventures in exploration & production activities
Payables for purchase of non-current assets
Payables due to joint ventures in exploration & production activities
Other payables
December 31, 2019
10,480
401
2,276
1,236
1,152
15,545
December 31, 2018
11,645
207
2,530
1,151
1,214
16,747
Trade and other payables were denominated in euro for €5,866
million and in US dollar for €8,371 million.
Because of the short-term maturity and conditions of remuneration of trade
and other payables, the fair values approximated the carrying amounts.
Payables due to related parties are described in note 36 – Transactions
with related parties.
18 | Finance debts
(€ million)
Banks
Ordinary bonds
Convertible bonds
Commercial papers
Other financial institutions
December 31, 2019
December 31, 2018
t
b
e
d
m
r
e
t
-
t
r
o
h
S
187
1,778
487
2,452
f
o
n
o
i
t
r
o
p
t
n
e
r
r
u
C
t
b
e
d
m
r
e
t
-
g
n
o
l
504
2,642
10
3,156
t
b
e
d
m
r
e
t
-
g
n
o
L
2,341
16,137
393
39
18,910
l
a
t
o
T
3,032
18,779
393
1,778
536
24,518
t
b
e
d
m
r
e
t
-
t
r
o
h
S
383
915
884
2,182
f
o
n
o
i
t
r
o
p
t
n
e
r
r
u
C
t
b
e
d
m
r
e
t
-
g
n
o
l
768
2,781
52
3,601
t
b
e
d
m
r
e
t
-
g
n
o
L
2,710
16,923
390
59
20,082
l
a
t
o
T
3,861
19,704
390
915
995
25,865
Finance debts decreased of €1,347 million due to repayments
made net of new issuances of €1,540 million and increased due
to currency translation differences relating to foreign subsidiaries
and debt denominated in foreign currency recorded by euro-
reporting subsidiaries for €249 million.
Commercial papers were issued by the Group’s financial subsidiaries.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
191
The following table reflects long-term debt as of December 31, 2019 by maturity:
(€ million)
Banks
Ordinary bonds
Convertible bonds
Other financial institutions
2021
750
930
11
1,691
2022
146
698
393
13
1,250
2023
838
1,879
14
2,731
2024
134
1,641
1
1,776
2025 and
thereafter
473
10,989
11,462
Long-term
debt
2,341
16,137
393
39
18,910
Eni entered into long-term borrowing facilities with the European
Investment Bank. These borrowing facilities are subject to the retention
of a minimum level of credit rating. According to the agreements, should
the Company loose the minimum credit rating, new guarantees could
be required to be agreed upon with the European Investment Bank. In
addition, Eni entered into long-term facilities subject to the retention of
certain financial ratios based on the Consolidated Financial Statements
of Eni with Citibank Europe Plc. In case of default, the bank may request
early repayment. At December 31, 2019, debts subjected to restrictive
covenants amounted to €1,243 million (€1,337 million at December 31,
2018). Eni was in compliance with those covenants.
Ordinary bonds consisted of bonds issued within the Euro Medium Term
Notes Program for a total of €15,030 million and other bonds for a total of
€3,749 million.
The following table provides a breakdown of ordinary bonds by issuing entity, maturity date, interest rate and currency as of December 31, 2019:
(€ milioni)
Issuing entity
Euro Medium Term Notes
Eni SpA
Eni SpA
Eni SpA
Eni SpA
Eni SpA
Eni SpA
Eni SpA
Eni SpA
Eni SpA
Eni SpA
Eni SpA
Eni SpA
Eni SpA
Eni SpA
Eni SpA
Eni Finance International SA
Eni Finance International SA
Eni Finance International SA
Eni Finance International SA
Other bonds
Eni SpA
Eni SpA
Eni SpA
Eni SpA
Eni SpA
Eni USA Inc
n
o
t
n
u
o
c
s
i
D
e
u
s
s
i
d
n
o
b
d
e
u
r
c
c
a
d
n
a
e
s
n
e
p
x
e
t
n
u
o
m
A
l
a
t
o
T
y
c
n
e
r
r
u
C
1,200
1,000
1,000
1,000
1,000
1,000
900
800
800
750
750
750
700
650
600
1,558
295
118
25
14,896
890
890
890
401
312
356
3,739
18,635
16
38
28
20
10
8
(4)
2
(1)
9
5
(4)
2
3
(4)
(3)
4
5
134
4
2
(1)
4
1
10
144
1,216
1,038
1,028
1,020
1,010
1,008
896
802
799
759
755
746
702
653
596
1,555
299
123
25
15,030
894
892
889
405
313
356
3,749
18,779
EUR
EUR
EUR
EUR
EUR
EUR
EUR
EUR
EUR
EUR
EUR
EUR
EUR
EUR
EUR
USD
EUR
GBP
YEN
USD
USD
USD
USD
USD
USD
from
2026
2028
y
t
i
r
u
t
a
M
to
2025
2020
2029
2020
2023
2026
2024
2021
2028
2024
2027
2034
2022
2025
2028
2027
2043
2021
2021
2023
2028
2029
2020
2040
2027
from
3.875
)
%
(
e
t
a
R
to
3.750
4.250
3.625
4.000
3.250
1.500
0.625
2.625
1.625
1.750
1.500
1.000
0.750
1.000
1.125
variable
5.441
4.750
1.955
4.000
4.750
4.250
4.150
5.700
7.300
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019
192
As of December 31, 2019, ordinary bonds maturing within 18
months amounted to €2,611 million. During 2019, new bonds issued
amounted to €1,635 million.
The following table provides a breakdown of convertible bonds issued
by Eni SpA as of December 31, 2019:
(€ million)
Eni SpA
n
o
t
n
u
o
c
s
i
D
e
u
s
s
i
d
n
o
b
d
e
u
r
c
c
a
d
n
a
e
s
n
e
p
x
e
(7)
t
n
u
o
m
A
400
l
a
t
o
T
393
y
c
n
e
r
r
u
C
EUR
y
t
i
r
u
t
a
M
2022
%
e
t
a
R
0.000
The non-dilutive equity-linked bond provides for a redemption value
linked to the market price of Eni’s shares. The bondholders have
"conversion" rights at certain times and/or in the presence of certain
events, while the bonds will be cash-settled. Accordingly, to hedge its
exposure, Eni purchased cash-settled call options relating to Eni shares
that will be settled on a net cash basis. The bond conversion price is
equal €17.62 and includes a 35% premium with respect to the Eni’s
share reference price at the date of issuance. The convertible bond
is measured at amortized cost. The conversion option, embedded in
the financial instrument issued, and the call option on Eni’s shares
acquired are valued at fair value with effects recognized through
profit and loss.
Eni has in place a program for the issuance of Euro Medium Term Notes up
to €20 billion, of which €14.9 billion were drawn as of December 31, 2019.
The following table provides a breakdown by currency of finance debt
and the related weighted average interest rates:
December 31, 2019
December 31, 2018
t
b
e
d
m
r
e
t
-
t
r
o
h
S
)
n
o
i
l
l
i
m
€
(
464
1,981
7
2,452
d
n
a
t
b
e
d
m
r
e
t
-
g
n
o
L
f
o
n
o
i
t
r
o
p
t
n
e
r
r
u
c
t
b
e
d
m
r
e
t
-
g
n
o
l
)
n
o
i
l
l
i
m
€
(
16,526
5,392
148
22,066
e
t
a
r
e
g
a
r
e
v
A
)
%
(
0.2
2.3
(0.7)
e
t
a
r
e
g
a
r
e
v
A
)
%
(
2.1
4.6
4.3
t
b
e
d
m
r
e
t
-
t
r
o
h
S
)
n
o
i
l
l
i
m
€
(
680
1,007
495
2,182
d
n
a
t
b
e
d
m
r
e
t
-
g
n
o
L
f
o
n
o
i
t
r
o
p
t
n
e
r
r
u
c
t
b
e
d
m
r
e
t
-
g
n
o
l
)
n
o
i
l
l
i
m
€
(
18,635
4,530
518
23,683
e
t
a
r
e
g
a
r
e
v
A
)
%
(
1.9
2.5
1.0
e
t
a
r
e
g
a
r
e
v
A
)
%
(
2.3
4.3
4.2
Euro
US dollar
Other currencies
As of December 31, 2019, Eni retained undrawn uncommitted
borrowing facilities amounting to €13,299 million (€12,484 million
at December 31, 2018) and undrawn long-term committed borrowing
facilities of €4,667 million (€5,214 million at December 31, 2018).
Those facilities bore interest rates reflecting prevailing conditions on
the marketplace. As of December 31, 2019, Eni was in compliance
with covenants and other contractual provisions in relation to
borrowing facilities.
Fair value of long-term debt, including the current portion of long-
term debt is described below:
(€ million)
Ordinary bonds
Convertible bonds
Banks
Other financial institutions
December 31, 2019
19,173
402
2,904
49
22,528
December 31, 2018
20,257
399
3,445
111
24,212
Fair value of finance debts was calculated by discounting the
expected future cash flows at discount rates ranging from -0.3% to
2.0% (-0.2% and 2.9% at December 31, 2018).
Because of the short-term maturity and conditions of remuneration
of short-term debts, the fair value approximated the carrying
amount.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
193
l
a
t
o
T
25,865
5,656
168
(13)
31,676
(2,417)
342
5
560
30,166
Total
10,836
6,552
17,388
188
383
3,478
20,094
661
1,138
111
25,865
8,289
CHANGES IN LIABILITIES ARISING FROM FINANCING ACTIVITIES
(€ million)
Carrying amount at December 31, 2018
First adoption IFRS 16
Reclassifications
Reclassification to liabilities directly associated with assets held for sale
Carrying amount at January 1, 2019
Cash flows
Currency translation differences
Changes in the scope of consolidation
Other non-monetary changes
Carrying amount at December 31, 2019
t
b
e
d
m
r
e
t
-
g
n
o
L
t
b
e
d
m
r
e
t
-
g
n
o
l
t
n
e
r
r
u
c
d
n
a
f
o
n
o
i
t
r
o
p
23,683
23,683
(1,701)
157
(73)
22,066
t
b
e
d
m
r
e
t
-
t
r
o
h
S
2,182
2,182
161
92
5
12
2,452
d
n
a
m
r
e
t
-
g
n
o
L
n
o
i
t
r
o
p
t
n
e
r
r
u
c
m
r
e
t
-
g
n
o
l
f
o
s
i
t
e
i
l
i
b
a
i
l
e
s
a
e
l
5,656
168
(13)
5,811
(877)
93
621
5,648
Other non-monetary changes include €668 million of lease liabilities
assumptions.
Lease liabilities are described in note 12 – Right-of-use assets and
lease liabilities.
Transactions with related parties are described in note 36 –
Transactions with related parties.
19 | Information on net borrowings
The analysis of net borrowings as defined in the "Financial Review", was as follows:
(€ million)
A. Cash and cash equivalents
B. Held-for-trading financial assets
C Liquidity (A+B)
D. Financing receivables
E. Short-term debt towards banks
F. Long-term debt towards banks
G. Bonds
H. Short-term debt towards related parties
I. Other short-term liabilities
J. Other long-term liabilities
K. Total borrowings less lease liabilities (E+F+G+H+I+J)
L. Net borrowings less lease liabilities (K-C-D)
M. Lease liabilities
N. Lease liabilities towards related parties
O. Total borrowings including lease liabilities (K+M+N)
P. Net borrowings including lease liabilities (O-C-D)
December 31, 2019
Non-current
December 31, 2018
Non-current
Current
5,994
6,760
12,754
287
187
504
2,642
46
2,219
10
5,608
(7,433)
884
5
6,497
(6,544)
Current
10,836
6,552
17,388
188
383
768
2,781
661
1,138
52
5,783
(11,793)
Total
5,994
6,760
12,754
287
187
2,845
19,172
46
2,219
49
24,518
11,477
5,635
13
30,166
17,125
2,341
16,530
39
18,910
18,910
4,751
8
23,669
23,669
2,710
17,313
59
20,082
20,082
5,783
(11,793)
20,082
20,082
25,865
8,289
Cash and cash equivalent are disclosed in note 5 – Cash and cash
equivalent.
Financial assets held for trading are disclosed in note 6 – Financial
assets held for trading.
Financing receivables are disclosed in note 16 – Other financial
assets.
Finance debts are disclosed in note 18 – Finance debts.
Liabilities for leased assets related for €1,976 million to the share
of joint operators in upstream projects operated by Eni which will
be recovered through a partner cash-call billing process. More
information is reported in note 12 – Right-of-use assets and lease
liabilities.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019
194
20 | Provisions
t
n
e
m
n
o
d
n
a
b
a
,
n
o
i
t
a
r
o
t
s
e
r
s
t
c
e
j
o
r
p
l
a
i
c
o
s
d
n
a
e
t
i
s
r
o
f
s
n
o
i
s
i
v
o
r
P
6,777
2,074
247
(313)
(7)
112
46
8,936
s
n
o
i
s
i
v
o
r
p
l
a
t
n
e
m
n
o
r
i
v
n
E
2,595
354
7
(299)
(25)
(30)
2,602
s
n
o
i
t
a
g
i
t
i
l
r
o
f
s
n
o
i
s
i
v
o
r
P
824
165
(2)
(43)
(105)
13
(2)
850
n
o
s
e
s
s
o
l
r
o
f
s
n
o
i
s
i
v
o
r
P
s
t
n
e
m
t
s
e
v
n
i
204
65
r
e
h
t
o
s
e
x
a
t
r
o
f
s
n
o
i
s
i
v
o
r
P
s
e
x
a
t
e
m
o
c
n
i
n
a
h
t
180
38
d
n
a
s
t
n
e
m
t
s
u
d
a
s
s
o
L
j
r
o
f
s
n
o
i
s
i
v
o
r
p
l
a
i
r
a
u
t
c
a
e
c
n
a
r
u
s
n
i
s
'
i
n
E
s
e
i
n
a
p
m
o
c
327
173
(24)
(175)
8
(3)
199
2
(83)
188
8
333
y
c
n
a
d
n
u
d
e
r
r
o
f
s
n
o
i
s
i
v
o
r
P
s
e
v
i
t
n
e
c
n
i
108
2
l
a
s
o
p
s
i
d
r
o
f
s
n
o
i
s
i
v
o
r
P
g
n
i
r
u
t
c
u
r
t
s
e
r
d
n
a
66
2
(11)
(29)
(12)
(10)
70
46
L
I
O
r
o
f
s
n
o
i
s
i
v
o
r
P
r
e
v
o
c
e
c
n
a
r
u
s
n
i
130
(19)
2
113
s
r
e
h
t
O
l
a
t
o
T
415 11,626
1,210
411
2,074
255
3
(928)
(51)
(202)
(7)
139
4
(6)
(68)
769 14,106
(€ million)
Carrying amount at December 31, 2018
New or increased provisions
Initial recognition and changes in estimates
Accretion discount
Reversal of utilized provisions
Reversal of unutilized provisions
Currency translation differences
Other changes
Carrying amount at December 31, 2019
Provisions for site restoration, abandonment and social projects include
the present value of the estimated costs that the Company expects to
incur for decommissioning oil and natural gas production facilities at the
end of the producing lives of fields, well-plugging, abandonment and site
restoration of the Exploration & Production segment for €8,411 million.
Initial recognitions and changes in estimates of €2,074 million were
mainly driven by a decrease in the discount rate curve and to a lesser
extent by the recognition of new decommissioning obligations due to
the activity of the year. The unwinding of discount recognized through
profit and loss for €247 million was determined based on discount rates
ranging from -0.1% to 6.1% (from -0.2% to 6.1% at December 31, 2018).
Main expenditures associated with decommissioning operations are
expected to be incurred over a 45-year period.
Provisions for environmental risks included the estimated costs for
environmental clean-up and remediation of soil and groundwater
in areas owned or under concession where the Group performed
in the past industrial operations that were progressively divested,
shut down, dismantled or restructured. The provision was accrued
because at the balance sheet date there is a legal or constructive
obligation for Eni to carry out environmental clean-up and remediation
and the expected costs can be estimated reliably. The provision
included the expected charges associated with strict liability related
to obligations of cleaning up and remediating polluted areas that met
the parameters set by the law at the time when the pollution occurred
but presently are no more in compliance with current environmental
laws and regulations, or because Eni assumed the liability borne by
other operators when the Company acquired or otherwise took over
site operations. Those environmental provisions are recognized when
an environmental project is approved by or filed with the relevant
administrative authorities or a constructive obligation has arisen
whereby the Company commits itself to performing certain cleaning-
up and restoration projects and a reliable cost estimation is available.
At December 31, 2019, environmental provision primarily related to
Eni Rewind SpA (former Syndial SpA) for €1,930 million and to the
Refining & Marketing business line for €416 million which includes the
costs of restoration and environmental remediation as a part of the
Memorandum of Understanding signed between Eni and the Ministry
for the Environment in December 2019.
Litigation provisions comprised expected liabilities associated with
legal proceedings and other matters arising from contractual claims,
including arbitrations, fines and penalties due to antitrust proceedings
and administrative matters. These provisions represent the Company’s
best estimate of the expected and probable liabilities associated with
ongoing litigation and related to the Exploration & Production segment
for €723 million.
Provisions for taxes other than income taxes related to the estimated
losses that the Company expects to incur to settle uncertain tax
matters and tax claims pending with tax authorities in relation to
uncertainties in applying rules in force for foreign subsidiaries of the
Exploration & Production segment for €169 million.
Loss adjustments and actuarial provisions of Eni’s insurance company
Eni Insurance DAC represented the estimated liabilities accrued on
the basis for third parties claims. Against such liability was recorded
receivables of €162 million recognized towards insurance companies
for reinsurance contracts.
Provisions for losses on investments included provisions relating to
investments whose loss exceeds the equity and primarily related
to Industria Siciliana Acido Fosforico - ISAF - SpA (in liquidation) for
€131 million.
Provisions for the OIL mutual insurance scheme included the estimated
future increase of insurance premiums which will be charged to Eni in
the next five years and that were accrued at the reporting date because
of the effective accident rate occurred in past reporting periods.
Provisions for redundancy incentives were recognized mainly due to
a restructuring program involving the Italian personnel related to past
reporting periods.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
21 | Provisions for employee benefits
(€ million)
Italian defined benefit plans
Foreign defined benefit plans
FISDE, foreign medical plans and other
Defined benefit plans
Other benefit plans
195
December 31, 2019
269
412
177
858
278
1,136
December 31, 2018
275
385
148
808
309
1,117
The liability relating to Eni's commitment to cover the healthcare
costs of personnel is determined on the basis of the contributions
paid by the Company.
benefit plan applicable to a specific category of employees) of Eni
gas e luce SpA for €107 million, jubilee awards for €25 million and
other long-term plans for €14 million.
Other employee benefit plans related to deferred monetary incentive
plans for €132 million, the isopensione plans (a post retirement
Present value of employee benefits, estimated by applying actuarial
techniques, consisted of the following:
2019
2018
d
e
n
fi
e
d
n
a
i
l
a
t
I
l
s
n
a
p
t
fi
e
n
e
b
d
e
n
fi
e
d
n
g
i
e
r
o
F
l
s
n
a
p
t
fi
e
n
e
b
n
g
i
e
r
o
f
,
E
D
S
I
F
s
n
a
p
l
l
a
c
i
d
e
m
r
e
h
t
o
d
n
a
t
fi
e
n
e
b
d
e
n
fi
e
D
s
n
a
p
l
t
fi
e
n
e
b
r
e
h
t
O
s
n
a
p
l
l
a
t
o
T
d
e
n
fi
e
d
n
g
e
r
o
F
i
l
s
n
a
p
t
fi
e
n
e
b
l
s
n
a
p
t
fi
e
n
e
b
i
n
g
e
r
o
f
,
E
D
S
I
F
s
n
a
p
l
l
a
c
i
d
e
m
r
e
h
t
o
d
n
a
t
fi
e
n
e
b
d
e
n
fi
e
D
s
n
a
p
l
t
fi
e
n
e
b
r
e
h
t
O
s
n
a
p
l
l
a
t
o
T
d
e
n
fi
e
d
n
a
i
l
a
t
I
275
925
148
1,348
309
1,657
284
997
135
1,416
194
1,610
(€ million)
Present value of benefit liabilities at beginning of year
Current cost
Interest cost
Remeasurements:
- actuarial (gains) losses due to changes
in financial assumptions
- experience (gains) losses
Past service cost and (gains) losses settlements
Plan contributions:
- employee contributions
Benefits paid
Reclassification to liabilities directly associated
with asset held for sale
Changes in the scope of consolidation
4
5
7
(2)
19
37
41
50
(9)
1
1
1
55
1
1
1
(2)
2
3
24
3
21
8
21
44
70
60
10
9
1
1
(15)
(28)
(9)
(52)
(88)
4
1
1
76
45
71
61
10
7
1
1
(140) (15)
Currency translation differences and other changes
48
1
49
2
51
1
Present value of benefit liabilities at end of year (a) 269 1,044
177
1,490
278
1,768
275
Plan assets at beginning of year
Interest income
Return on plan assets
Plan contributions:
- employee contributions
- employer contributions
Benefits paid
Changes in the scope of consolidation
Currency translation differences and other changes
Plan assets at end of year (b)
Asset ceiling at beginning of year
Change in asset ceiling
Asset ceiling at end of year (c)
545
20
23
14
1
13
(19)
49
632
5
(5)
545
20
23
14
1
13
(19)
49
632
5
(5)
545
20
23
14
1
13
(19)
49
632
5
(5)
27
31
(25)
(31)
6
2
1
1
(35)
(8)
(90)
25
925
588
17
(21)
25
1
24
(26)
(64)
26
545
5
5
2
2
13
1
12
1
29
37
(11)
(30)
19
3
1
1
42
1
30
29
1
115
71
38
19
(1)
20
118
1
1
(9)
(59)
(74)
(133)
(8)
(90)
30
4
(8)
(2)
(92)
3
33
148
1,348
309
1,657
588
17
(21)
25
1
24
(26)
(64)
26
545
5
5
588
17
(21)
25
1
24
(26)
(64)
26
545
5
5
Net liability recognized at end of year (a-b+c)
269
412
177
858
278
1,136
275
385
148
808
309
1,117
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019
196
Employee benefit plans included the liability attributable to partners
operating in exploration and production activities of €175 million
(€181 million at December 31, 2018). Eni recorded a receivable for
an amount equivalent to such liability.
Costs charged to the profit and loss account consisted of the
following:
(€ million)
2019
Current cost
Past service cost and (gains) losses on settlements
Interest cost (income), net:
- interest cost on liabilities
- interest income on plan assets
Total interest cost (income), net
- of which recognized in "Payroll and related cost"
- of which recognized in "Financial income (expense)"
Remeasurements for long-term plans
Total
- of which recognized in "Payroll and related cost"
- of which recognized in "Financial income (expense)"
2018
Current cost
Past service cost and (gains) losses on settlements
Interest cost (income), net:
- interest cost on liabilities
- interest income on plan assets
Total interest cost (income), net
- of which recognized in "Payroll and related cost"
- of which recognized in "Financial income (expense)"
Remeasurements for long-term plans
Total
- of which recognized in "Payroll and related cost"
- of which recognized in "Financial income (expense)"
Italian
defined
benefit
plans
Foreign
defined
benefit
plans
FISDE,
foreign
medical
plans
and other
Defined
benefit
plans
Other
benefit
plans
19
1
37
(20)
17
17
37
20
17
27
2
31
(17)
14
14
43
29
14
4
4
4
4
4
4
4
4
4
4
2
8
3
3
3
13
10
3
2
1
2
2
2
5
3
2
21
9
44
(20)
24
24
54
30
24
29
3
37
(17)
20
20
52
32
20
55
(2)
1
1
1
1
55
55
42
115
1
1
1
30
188
188
Total
76
7
45
(20)
25
1
24
1
109
85
24
71
118
38
(17)
21
1
20
30
240
220
20
Costs of defined benefit plans recognized in other comprehensive income consisted of the following:
(€ milioni)
Remeasurements
Actuarial (gains)/losses due to changes in financial assumptions
Experience (gains) losses
Return on plan assets
Change in asset ceiling
2019
2018
Italian
defined
benefit
plans
Foreign
defined
benefit
plans
FISDE,
foreign
medical
plans and
other
7
(2)
5
50
(9)
(23)
(5)
13
3
21
24
Total
60
10
(23)
(5)
42
Italian
defined
benefit
plans
Foreign
defined
benefit
plans
FISDE,
foreign
medical
plans and
other
(31)
6
21
5
1
1
1
1
12
13
Total
(30)
19
21
5
15
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
197
Plan assets consisted of the following:
(€ million)
December 31, 2019
Plan assets with a quoted market price
Plan assets without a quoted market price
December 31, 2018
Plan assets with a quoted market price
Plan assets without a quoted market price
Cash and
cash
equivalents
Equity
securities
Debt
securities
Real
estate
Derivatives
Investment
funds
32
32
115
115
39
39
37
37
388
388
238
238
7
7
6
6
2
2
2
2
79
79
56
56
Assets
held by
insurance
company
17
3
20
18
3
21
Other
Total
65
65
70
70
629
3
632
542
3
545
The main actuarial assumptions used in the measurement of the liabilities at year-end and in the estimate of costs expected for 2020
consisted of the following:
2019
Discount rate
Rate of compensation increase
Rate of price inflation
Life expectations on retirement at age 65
2018
Discount rate
Rate of compensation increase
Rate of price inflation
Life expectations on retirement at age 65
Italian defined
benefit plans
Foreign defined
benefit plans
FISDE, foreign
medical plans
and other
Other benefit
plans
(%)
(%)
(%)
(years)
(%)
(%)
(%)
(years)
0.7
1.7
0.7
1.5
2.5
1.5
0.0-13.7
1.3-12.5
0.8-11.3
13-25
0.8-18.0
1.5-16.5
0.8-16.0
13-25
0.7
0.7
24
1.5
1.5
24.0
0.0-0.7
0.7
0.2-1.5
1.5
The following is an analysis by geographical area related to the main actuarial assumptions used in the valuation of the principal foreign
defined benefit plans:
2019
Discount rate
Rate of compensation increase
Rate of price inflation
Life expectations on retirement at age 65
2018
Discount rate
Rate of compensation increase
Rate of price inflation
Life expectations on retirement at age 65
Euro area
0.8-1.0
1.3-3.0
1.3-2.0
21-22
1.5-1.9
1.5-3.0
1.5-2.0
21-22
(%)
(%)
(%)
(years)
(%)
(%)
(%)
(years)
Rest of
Europe
0.0-2.0
2.5-3.6
0.8-3.1
24-25
0.8-2.9
2.5-3.8
0.8-3.3
23-25
Africa
Others areas
Foreign
defined
benefit plans
2.6-13.7
2.0-12.5
2.6-11.3
13-17
3.7-18.0
5.0-16.5
3.7-16.0
13-17
7.3-11.3
10.0-11.3
3.3-5.0
8.0-13.3
10.0-13.3
3.5-5.0
0.0-13.7
1.3-12.5
0.8-11.3
13-25
0.8-18.0
1.5-16.5
0.8-16.0
13-25
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019
198
The effects of a possible change in the main actuarial assumptions at the end of the year are listed below:
(€ million)
December 31, 2019
Italian defined benefit plans
Foreign defined benefit plans
FISDE, foreign medical plans and other
Other benefit plans
December 31, 2018
Italian defined benefit plans
Foreign defined benefit plans
FISDE, foreign medical plans and other
Other benefit plans
Discount rate
0.5%
Increase
0.5%
Decrease
Rate of price
inflation
0.5%
Increase
Rate of
increases in
pensionable
salaries
0.5%
Increase
Healthcare
cost trend
rate
0.5%
Increase
Rate of
increases to
pensions in
payment
0.5%
Increase
(12)
(67)
(9)
(4)
(12)
(58)
(7)
(5)
13
77
10
1
13
65
8
3
8
31
1
8
23
1
18
15
34
18
10
6
The sensitivity analysis was performed based on the results for
each plan through assessments calculated considering modified
parameters.
The amount of contributions expected to be paid for employee
benefit plans in the next year amounted to €130 million, of which
€57 million related to defined benefit plans.
The following is an analysis by maturity date of the liabilities for
employee benefit plans and their relative weighted average duration:
(€ million)
December 31, 2019
2020
2021
2022
2023
2024
2025 and thereafter
Weighted average duration (years)
(years)
December 31, 2018
2019
2020
2021
2022
2023
2024 and thereafter
Weighted average duration (years)
(years)
Italian defined
benefit plans
Foreign defined
benefit plans
FISDE, foreign medical
plans and other
Other benefit plans
17
16
12
10
15
199
9.4
15
16
18
14
11
201
10.1
33
35
32
39
49
224
18.1
54
56
63
64
74
74
17.4
9
8
7
7
7
139
13.3
9
7
6
6
6
114
12.8
73
68
61
17
14
45
3.0
81
72
67
20
17
57
2.6
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
22 | Deferred tax assets and liabilities
(€ million)
Deferred tax liabilities before offsetting
Deferred tax assets available for offset
Deferred tax liabilities
Deferred tax assets before offsetting (net of accumulated write-down provisions)
Deferred tax liabilities available for offset
Deferred tax assets
The most significant temporary differences giving rise to net deferred tax liabilities are disclosed below:
(€ million)
Deferred tax liabilities
Accelerated tax depreciation
Leasing
Difference between the fair value and the carrying amount of assets acquired
Site restoration and abandonment (tangible assets)
Application of the weighted average cost method in evaluation of inventories
Other
Deferred tax assets, gross
Carry-forward tax losses
Site restoration and abandonment (provisions for contingencies)
Timing differences on depreciation and amortization
Accruals for impairment losses and provisions for contingencies
Leasing
Impairment losses
Over/Under lifting
Employee benefits
Unrealized intercompany profits
Other
Accumulated write-downs of deferred tax assets
Deferred tax assets, net
The following table summarizes the changes in deferred tax liabilities and assets:
199
December 31, 2019
9,583
(4,663)
4,920
9,023
(4,663)
4,360
December 31, 2018
7,956
(3,684)
4,272
7,615
(3,684)
3,931
December 31, 2019
December 31, 2018
6,796
1,375
617
126
97
572
9,583
(6,065)
(2,242)
(2,022)
(1,513)
(1,385)
(946)
(525)
(209)
(120)
(740)
(15,767)
6,744
(9,023)
6,612
849
85
44
366
7,956
(5,528)
(1,986)
(2,104)
(1,460)
(792)
(604)
(212)
(124)
(546)
(13,356)
5,741
(7,615)
(€ million)
Carrying amount at December 31, 2018
Changes in accounting policies (IFRS 16)
Carrying amount at January 1, 2019
Additions
Deductions
Currency translation differences
Other changes
Carrying amount at December 31, 2019
Carrying amount at December 31, 2017
Changes in accounting policies (IFRS 15)
Carrying amount at January 1, 2018
Additions
Deductions
Currency translation differences
Change in the scope of consolidation
Other changes
Carrying amount at December 31, 2018
Deferred tax
liabilities, gross
7,956
1,470
9,426
1,265
(1,205)
194
(97)
9,583
10,169
37
10,206
1,147
(802)
283
(2,778)
(100)
7,956
Deferred tax
assets, gross
(13,356)
(1,470)
(14,826)
(2,091)
1,407
(182)
(75)
(15,767)
(13,609)
(237)
(13,846)
(1,478)
1,523
(278)
813
(90)
(13,356)
Accumulated
write-downs of
deferred tax assets
5,741
5,741
1,161
(174)
34
(18)
6,744
5,262
5,262
253
(43)
71
198
5,741
Deferred tax assets,
net of impairments
(7,615)
(1,470)
(9,085)
(930)
1,233
(148)
(93)
(9,023)
(8,347)
(237)
(8,584)
(1,225)
1,480
(207)
813
108
(7,615)
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019
200
The first application of IFRS 16 is disclosed in note 3 – Changes in
accounting policies.
Carry-forward tax losses amounted to €21,360 million out of which
€15,256 million can be carried forward indefinitely. Carry-forward tax
losses were €12,039 million and €9,321 million at Italian subsidiaries
and foreign subsidiaries, respectively. Deferred tax assets recognized
on these losses amounted to €2,936 million and €3,129 million,
respectively.
Italian taxation law allows the carry-forward of tax losses
indefinitely. Foreign taxation laws generally allow the carry-
forward of tax losses over a period longer than five years, and
in many cases, indefinitely. A tax rate of 24% was applied to tax
losses of Italian subsidiaries to determine the portion of the carry-
forwards tax losses, which will be utilized in future years to offset
expected taxable profit. The corresponding average rate for foreign
subsidiaries was 33.6%.
Accumulated write-downs of deferred tax assets related to Italian
companies for €5,329 million and non-Italian companies for €1,415
million.
Taxes are also described in note 32 – Income taxes.
23 | Derivative financial instruments and hedge accounting
(€ million)
Non-hedging derivatives
Derivatives on exchange rate
- Currency swap
- Interest currency swap
- Outright
Derivatives on interest rate
- Interest rate swap
Derivatives on commodities
- Future
- Over the counter
- Other
Trading derivatives
Derivatives on commodities
- Over the counter
- Future
- Options
Cash flow hedge derivatives
Derivatives on commodities
- Over the counter
- Future
- Options
Option embedded in convertible bonds
Gross amount
Offsetting
Net amount
Of which:
- current
- non-current
December 31, 2019
December 31, 2018
Fair value
asset
Fair value
liability
Level of Fair
value
Fair value
asset
Fair value
liability
Level of Fair
value
97
26
8
131
13
13
192
89
12
293
437
2,387
348
21
2,756
1
34
35
11
3,239
(612)
2,627
2,573
54
43
5
48
34
34
181
58
239
321
1,953
313
22
2,288
596
148
2
746
11
3,366
(612)
2,754
2,704
50
2
2
2
2
1
2
2
2
1
2
2
1
2
2
99
14
3
116
18
18
1,060
306
1
1,367
1,501
992
367
80
1,439
46
71
5
122
6
6
1,107
284
5
1,396
1,524
1,031
263
71
1,365
311
196
26
337
21
3,298
(1,636)
1,662
1,594
68
15
211
21
3,121
(1,636)
1,485
1,445
40
2
2
2
2
1
2
2
2
1
2
2
1
2
Derivative fair values were estimated on the basis of market quotations
provided by primary info-provider or, alternatively, appropriate valuation
techniques generally adopted in the marketplace.
Fair values of non-hedging derivatives consisted of derivatives that did
not meet the formal criteria to be designated as hedges under IFRS.
Fair values of trading derivatives consisted of derivatives entered for
trading purposes and proprietary trading.
Fair value of cash flow hedge derivatives related to commodity hedges
were entered into by the Gas & Power segment. These derivatives were
entered into to hedge variability in future cash flows associated with
highly probable future sale transactions of gas or electricity or on already
contracted sales due to different indexation mechanisms of supply
costs versus selling prices. A similar scheme applies to exchange rate
hedging derivatives. The effects of the measurement at fair value of cash
flow hedge derivatives are given in note 25 – Shareholders’ equity and
in note 29 – Costs. Information on hedged risks and hedging policies
is disclosed in note 27 – Guarantees, commitments and risks - Risk
factors.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
201
Options embedded in convertible bonds relate to equity-linked cash
settled. More information is disclosed in note 18 – Finance debts.
The offsetting of financial derivatives related to the Gas & Power
segment.
During 2019, there were no transfers between the different hierarchy
levels of fair value.
Hedging derivative instruments are disclosed below:
(€ million)
Cash flow hedge derivatives
Derivatives on commodity
- Over the counter
- Future
December 31, 2019
December 31, 2018
Nominal amount
of the hedging
instrument
Change in fair
value
(effective
hedge)
Change in fair
value
(ineffective
hedge)
Nominal amount
of the hedging
instrument
Change in fair
value
(effective
hedge)
Change in fair
value
(ineffective
hedge)
2,179
1,245
3,424
(1,357)
(61)
(1,418)
(2)
(2)
3,528
71
3,599
404
(6)
398
2
(2)
In 2019, the exposure to the exchange rate risk deriving from
securities denominated in US dollars included in the strategic
liquidity portfolio amounting to €1,902 million was hedged by
using, in a fair value hedge relationship, negative exchange
differences for €21 million resulting on a portion of bonds
denominated in US dollars amounting to €1,844 million.
The breakdown of the underlying asset or liability by type of risk
hedged under cash flow hedge is provided below:
December 31, 2019
December 31, 2018
Change
of the underlying asset
used for the calculation
of hedging
ineffectiveness
CFH
reserve
Reclassification
adjustments
Change of the
underlying asset
used for the calculation
of hedging
ineffectiveness
CFH
reserve
Reclassification
adjustments
1,444
1,444
(656)
(656)
(739)
(739)
(389)
(389)
(13)
(13)
642
642
(€ million)
Cash flow hedge derivatives
Commodity price risk
- Planned sales
Eni’s results of operations are affected by fluctuations in the price of
commodities. To that end, Eni enters into commodities derivatives
traded the organized markets (like MTF and OTF) and commodities
derivatives traded over the counter (swaps, forward, contracts
for differences and options on commodities) with underlying
commodities being crude oil, gas, refined products, electricity or
emission certificates that are not settled through physical delivery of
the underlying commodity but are designated as hedging instruments
in a cash flow hedge relation.
The existence of a relationship between the hedged item and the
hedging derivative is checked at inception to verify eligibility for
hedge accounting by observing the offset in changes of the fair values
at both the underlying commodity and the derivative. The hedging
relationship is also stress-tested against the level of credit risk of the
counterparty in the derivative transaction.
The hedge ratio is defined consistently with the Company’s risk
management objectives, under a defined risk management strategy.
The hedging relationship is discontinued when it ceases to meet the
qualifying criteria and the risk management objectives on the basis of
which hedge accounting has initially been applied.
More information is reported in note 27 – Guarantees, Commitments
and Risks – Financial risks.
Effects recognized in other operating profit (loss)
Other operating profit (loss) related to derivative financial instruments on commodity was as follows:
(€ million)
Net income (loss) on cash flow hedging derivatives
Net income (loss) on other derivatives
2019
(2)
289
287
2018
129
129
2017
12
(44)
(32)
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019
202
Net income (loss) on cash flow hedging derivatives related to the
ineffective portion of the hedging relationship on commodity derivatives
was recognized through profit and loss in the Gas & Power segment.
Net income (loss) on other derivatives included the fair value
measurement and settlement of commodity derivatives which could
not be elected for hedge accounting under IFRS because they related to
net exposure to commodity risk and derivatives for trading purposes
and proprietary trading.
Effects recognized in finance income (loss)
Finance income (loss) on derivative financial instruments consisted of the following:
(€ million)
Derivatives on exchange rate
Derivatives on interest rate
2019
9
(23)
(14)
2018
(329)
22
(307)
2017
809
28
837
Net finance income from derivative financial instruments was
recognized in connection with the fair value valuation of certain
derivatives which lacked the formal criteria to be treated in accordance
with hedge accounting under IFRS, as they were entered into for
amounts equal to the net exposure to exchange rate risk and interest
rate risk, and as such, they cannot be referred to specific trade or
financing transactions. Exchange rate derivatives were entered into in
order to manage exposures to foreign currency exchange rates arising
from the pricing formulas of commodities in the Gas & Power segment.
Finance income (expense) with related parties is disclosed in note 36 –
Transactions with related parties.
24 | Assets held for sale and liabilities directly associated with assets held for sale
As of December 31, 2019, assets held for sale related to sales of
tangible for €18 million.
In the course of 2019, Eni finalized the sale of Agip Oil Ecuador BV,
which retains a service contract for the development of Villano oil field,
and of a minority investment.
25 | Shareholders’ equity
Eni shareholders' equity
(€ million)
Share capital
Retained earnings
Cumulative currency translation differences
Legal reserve
Reserve for treasury shares
Reserve related to the fair value of cash flow hedging derivatives net of the tax effect
Reserve related to the defined benefit plans net of tax effect
Other comprehensive income on equity-accounted investments
Other comprehensive income on other investments
Other reserves
Treasury shares
Interim dividend
Net profit (loss) for the year
December 31, 2019
4,005
37,436
7,209
959
981
(465)
(173)
60
12
190
(981)
(1,542)
148
47,839
December 31, 2018
4,005
36,702
6,605
959
581
(9)
(130)
66
15
190
(581)
(1,513)
4,126
51,016
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 203
Share capital
As of December 31, 2019, the parent company’s issued share capital
consisted of €4,005,358,876 represented by 3,634,185,330 ordinary
shares without nominal value (same amounts as of December 31,
2018).
On May 14, 2019, Eni’s Shareholders’ Meeting resolved: (i) to distribute
a dividend of €0.41 per share, with the exclusion of treasury shares
held at the ex-dividend date, in full settlement of the 2018 dividend of
€0.83 per share, of which €0.42 per share was already paid as interim
dividend in September 2018. The final amount was paid on 22 May
2019, to shareholders on the register on May 20, 2019, record date
on May 21, 2019; (ii) to authorise the Board of Directors – pursuant
to and for the purposes of Article 2357 of the Italian Civil Code – to
proceed, within a period of eighteen months from the date of the
resolution, with the purchase of a maximum number of shares equal to
67,000,000 ordinary shares of the Company, representing about 1.84%
of the share capital of Eni SpA, for a total outlay of up to €1,200 million.
In execution of this resolution at December 31, 2019, 28,590,482
shares were acquired for a total consideration of €400 million.
Legal reserve
This reserve represents earnings restricted from the payment of
dividends pursuant to Article 2430 of the Italian Civil Code. The legal
reserve has reached the maximum amount required by the Italian Law.
Reserve for treasury shares
The reserve for treasury shares represents the reserve that was
established in previous reporting period to repurchase the Company
shares in accordance with resolutions at Eni’s Shareholders’ Meetings.
Other Comprehensive Income reserves
Cash flow hedge derivatives
Defined benefit plans(*)
(€ million)
Reserve as of December 31, 2018
Changes of the year
Foreign currency translation differences
Change in scope of consolidation
Reversal to inventories adjustments
Reclassification adjustments
Reserve as of December 31, 2019
Reserve as of December 31, 2017
Changes of the year
Foreign currency translation differences
Change in scope of consolidation
Reversal to inventories adjustments
Reclassification adjustments
Reserve as of December 31, 2018
e
v
r
e
s
e
r
s
s
o
r
G
x
a
t
d
e
r
r
e
f
e
D
s
e
i
t
i
l
i
b
a
i
l
e
v
r
e
s
e
r
t
e
N
e
v
r
e
s
e
r
s
s
o
r
G
x
a
t
d
e
r
r
e
f
e
D
s
e
i
t
i
l
i
b
a
i
l
e
v
r
e
s
e
r
t
e
N
(13)
(1,418)
4
411
(9)
(1,007)
36
739
(656)
240
399
(10)
(642)
(13)
(10)
(214)
191
(57)
(116)
26
525
(465)
183
283
3
174
4
(7)
(468)
(9)
(143)
(49)
(3)
5
13
5
(1)
(130)
(44)
(3)
4
(190)
17
(173)
(133)
(15)
1
4
19
(2)
(1)
(3)
(114)
(17)
1
Other
comprehensive
income on
equity-accounted
investments
66
(6)
Investments
valued at fair
value
15
(3)
60
90
(24)
12
15
(143)
13
(130)
66
15
(*) OCI for defined benefit plans at December 31, 2019 includes €7 million related to equity-accounted investments.
Other reserves
Other reserves related to: (i) a reserve of €127 million representing
the increase in Eni shareholders’ equity associated with a business
combination under common control, whereby the parent company Eni
SpA divested its subsidiaries; (ii) a reserve of €63 million deriving from
Eni SpA’s equity.
Cumulative foreign currency translation differences
The cumulative foreign currency translation differences arose from the
translation of financial statements denominated in currencies other than
euro.
Meeting approved the Long-Term Monetary Incentive Plan 2017-
2019 and empowered the Board of Directors to execute the Plan by
authorizing it to dispose up to a maximum of 11 million of treasury
shares in service of the Plan.
Interim dividend
The interim dividend for the year 2019 amounted to €1,542 million
corresponding to €0,43 per share, as resolved by the Board of
Directors on September 19, 2019, in accordance with Article 2433-
bis, paragraph 5 of the Italian Civil Code; the dividend was paid on
September 25, 2019.
Treasury shares
A total of 61,635,679 of Eni’s ordinary shares (33,045,197 at December
31, 2018) were held in treasury for a total cost of €981 million (€581
million at December 31, 2018). On April 13, 2017, the Shareholders
Distributable reserves
As of December 31, 2019, Eni shareholders’ equity included
distributable reserves of approximately €43 billion.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019
204
Reconciliation of net profit and shareholders’ equity of the parent company Eni SpA to consolidated net profit
and shareholders’ equity
(€ million)
As recorded in Eni SpA's Financial Statements
Excess of net equity stated in the separate accounts of consolidated
subsidiaries over the corresponding carrying amounts of the parent company
Consolidation adjustments:
- difference between purchase cost and underlying carrying amounts of net equity
- adjustments to comply with Group accounting policies
- elimination of unrealized intercompany profits
- deferred taxation
Non-controlling interest
As recorded in Consolidated Financial Statements
26 | Other information
Supplemental cash flow information
(€ million)
Investment in consolidated subsidiaries and businesses
Current assets
Non-current assets
Net borrowings
Current and non-current liabilities
Net effect of investments
Fair value of investments held before the acquisition of control
Non-controlling interests
Gain on a bargain purchase
Purchase price
less:
Cash and cash equivalents
Consolidated subsidiaries and businesses net of cash and cash equivalent acquired
Disposal of consolidated subsidiaries and businesses
Current assets
Non-current assets
Net borrowings
Current and non-current liabilities
Net effect of disposals
Reclassification of foreign currency translation differences among other items of comprehensive income
Fair value of share capital held after the sale of control
Fair value valuation for business combination
Gain (loss) on disposal
Selling price
less:
Cash and cash equivalents
Consolidated subsidiaries and businesses net of cash and cash equivalent divested disposed of
Net profit
Shareholders’ equity
2019
2,978
2018
3,173
December 31, 2019
41,636
December 31, 2018
42,615
(2,800)
(134)
(6)
(348)
(74)
405
155
(7)
148
862
177
59
4,137
(11)
4,126
5,211
202
1,424
(593)
20
47,900
(61)
47,839
7,183
153
2,000
(519)
(359)
51,073
(57)
51,016
2019
2018
2017
1
12
(6)
7
(2)
5
5
77
188
11
(57)
219
(24)
16
211
(24)
187
44
198
11
(47)
206
(50)
(8)
148
(29)
119
328
5,079
785
(3,470)
2,722
113
(3,498)
889
13
239
(286)
(47)
166
814
(252)
(205)
523
2,148
2,671
(9)
2,662
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
205
Investments in 2019 concerned: (i) the acquisition of 60% stake of SEA
SpA, which supplies services and solutions for energy efficiency in the
residential and industrial segments in Italy; (ii) the acquisition of the
residual 32% interest in the joint operation Petroven Srl, which operates
storage facilities of petroleum products.
Disposals in 2019 concerned the sale of the 100% of the stake of Agip
Oil Ecuador BV, which retains a service contract for the development of
the Villano oil field.
Investments in 2018 concerned: (i) the acquisition of the business
by Versalis SpA of the “bio” activities of the Mossi & Ghisolfi Group,
related to development, industrialization, licensing of bio-chemical
technologies and processes based on use of renewable sources for
€75 million; (ii) the acquisition of the remaining 51% stake in the Gas
Supply Company of Thessaloniki - Thessalia SA which distributes and
sells gas in Greece for €24 million, net of cash acquired of €28 million;
(iii) the acquisition of the company Mestni Plinovodi distribucija
plina doo, which distributes and sells gas in Slovenia for €15 million,
net of cash acquired for €1 million. The gain from bargain purchase,
recognized in Other income and revenues, was due to the obtainable
synergies from the greater ability to recover the investments made by
the acquired company due to the combination of customer portfolios.
Disposals in 2018 concerned: (i) the loss of control of Eni Norge
AS resulting from the business combination with Point Resources
AS, with the establishment of the equity-accounted joint venture
Vår Energi AS (Eni's interest 69.60%), that will develop the
project portfolio of the combined entities. The operation entailed
the change in scope of consolidation of €2,486 million of net
assets, of which cash and cash equivalents for €258 million, the
recognition of the investment in Vår Energi AS for €3,498 million
and a fair value gain of €889 million, net of negative exchange rate
differences of €123 million; (ii) the sale of 98.99% (entire stake
owned) of Tigáz Zrt and Tigáz Dso (100% Tigáz Zrt) operating in
the gas distribution business in Hungary to the MET Holding AG
group for €145 million net of cash divested of €13 million; (iii) the
sale by Lasmo Sanga Sanga of the business relating to a 26.25%
stake (entire stake owned) in the PSA of the Sanga Sanga gas
and condensates field for €33 million; (iv) the sale of 100% of
Eni Croatia BV, which owns shares of gas projects in Croatia to
INA-Industrija Nafte dd for €20 million, net of cash divested of €15
million; (v) the sale of 100% of Eni Trinidad and Tobago Ltd, which
holds a share of a gas project in Trinidad and Tobago for €10 million.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019 206
27 | Guarantees, commitments and risks
Guarantees
(€ million)
Consolidated subsidiaries
Unconsolidated subsidiaries
Joint ventures and associates
Others
December 31, 2019
4,323
197
4,075
267
8,862
December 31, 2018
5,082
196
4,056
163
9,497
Guarantees include the guarantees issued by Eni SpA on behalf of
third-party contractors and lenders who have a certain contractual
obligations to build and finance the construction of an LNG Floating
Production unit for the development of the Coral gas reserves discovered
in Area 4 offshore Mozambique. The total value of the contract is €4,673
million. Eni is operator of the project with a 25% indirect interest through
a 35.71% stake in the joint operation Mozambique Rovuma Venture SpA.
The final investment decision (FID) for the Coral project was made on
June 1, 2017. The FLNG plant is designed to treat approximately 3.37
million tonnes per year of LNG. A special purpose entity was established,
Coral FLNG SA (Eni’s interest 25%). This entity will operate the vessel in
accordance with a service agreement (EPCC) for the liquefaction, storage
and loading of the LNG on behalf of the Concessionaires of Area 4 and of
the other two partners of Mozambique Rovuma Venture SpA, CNPC and
ExxonMobil in proportion to their participating interest in the Exploration
and Production Concession Contract (EPCC) of Area 4, equal to 20% and
25%, respectively. The LNG will be supplied to BP under a long-term LNG
sale and purchase agreement with a take-or-pay clause and a twenty-
year term, providing an option of extending the duration for up to ten
consecutive years. Eni issued a parent company guarantee, whereby it
irrevocably and unconditionally guarantees the Technip – JGC – Samsung
Heavy Industries (TJS) consortium (the beneficiaries) for the due and
proper performance of the obligations of Coral FLNG SA in connection with
execution of the Engineering Procurement Construction Installation and
Commissioning (EPCIC) contract, up to the maximum liability of €1,168
million equal to 25% of the value of the contract. The maximum liability
will be automatically reduced by any amount paid to the beneficiaries
in respect of the guaranteed obligations. The financing of the project is
carried out partly through funds provided by the venturers and partly by
a project financing with Export Credit Agencies and commercial banks
for a total amount of €4,164 million. During the construction and the
commissioning of the FLNG plant, the project financing agreement will be
supported by a debt service undertaking (DSU), up to a maximum liability
of €1,425 million in proportion to Eni’s participating interest equal to
25% in the industrial initiative. Subsequently, in the running phase of the
plant, once the performance tests of the vessel have been validated by
the lenders, that guarantee will be released and the financing facility will
convert to non-recourse, terminating the obligations of the venturers of
Area 4 towards the lenders. Once vessel operations start, the lenders will
be guaranteed only by the cash flows of the sale of LNG volumes treated
by the vessel and delivered to the buyer, excluding the gas reserves from
the scope of the guarantee. The financing and any collateral costs will be
reimbursed to the lenders through a “pay-when-paid” clause, whereby
loan repayments will be made through the cash flows associated with
the sale of the LNG arising from the project to the long-term buyer,
without any obligations from Eni and Concessionaires to guarantee
the performance of Coral FLNG SA towards the lenders. Furthermore,
the Concessionaries opened a credit facility which committed each
Concessionary to finance pro-quota: (i) the share of capital expenditures
to be borne by the Mozambique State-owned company ENH up to a
maximum liability of €123 million in Eni’s share; (ii) the share of the debt
service undertaking by ENH up to a maximum liability of €158 million
in Eni’s share. As a final point, as provided by the EPCC that regulates
the petroleum activities in Area 4, Eni SpA in its capacity as parent
company of the operator Mozambique Rovuma Venture SpA has provided
concurrently with the approval of the initial development plan of the Area
reserves, an irrevocable and unconditional parent company guarantee in
respect of any possible claims or any contractual breaches in connection
with the petroleum activities to be carried out in the contractual area,
including those activities in charge of the special purpose entities like
Coral FLNG SA, to benefit of the Government of Mozambique and third
parties. The obligations of the guarantor towards the Government of
Mozambique are unlimited (non-quantifiable commitments), whereas
they provide a maximum liability of €1,335 million in respect of third-
parties claims. This guarantee will be effective until the completion of
any decommissioning activity related to both the development plan
of Coral as well as any development plan to be executed within Area
4 (particularly the Mamba project). This parent company guarantee
issued by Eni covering 100% of the aforementioned obligations was
taken over by the other concessionaires (Kogas, Galp and ENH) and by
ExxonMobil and CNPC shareholders of the joint operation Mozambico
Rovuma Venture SpA, in proportion to their respective participating
interest in the EPCIC of Area 4.
Guarantees issued on behalf of consolidated subsidiaries of €4,323
million (€5,082 million at December 31, 2018) primarily consisted of
guarantees given to third parties relating to bid bonds and performance
bonds for €2,886 million (€2,576 million at December 31, 2018). In 2019
a bank guarantee of €1,010 million issued on behalf of GasTerra to obtain
the waiver to a temporary seizure of Eni’s investment in Eni International
BV, which was ordered by a Netherlands Court in July 2016, was settled.
In July 2019, the arbitration proceeding, initiated by the parties to settle
the dispute, issued an award favourable to Eni and ruled the claim of
GasTerra for a price adjustment to the gas supplies to be without merit,
which in the first partial award was the basis whereby GasTerra's
obtained the seizure order. On July 24, 2019 upon Eni’s request and
GasTerra's consent the bank guarantee was terminated. GasTerra has
reserved its rights of appeal. At December 31, 2019, the underlying
commitment issued on behalf of consolidated subsidiaries covered
by such guarantees was €4,013 million (€5,000 million at December
31, 2018).
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
207
Guarantees issued on behalf of joint ventures and associates of €4,075
million (€4,056 million at December 31, 2018) primarily consisted
of: (i) unsecured guarantees and other guarantees for €1,676 million
issued towards banks and other lending institutions in relation to loans
and lines of credit received (€1,664 million at December 31, 2018), of
which €1,425 million (€1,397 million at December 31, 2018) related to
guarantees issued as part of the Coral development project in Area 4
offshore Mozambique on behalf of Coral South FLNG DMCC with respect
to the financing agreements of the project with Export Credit Agencies
and banks; and (ii) guarantees given to third parties relating to bid bonds
and performance bonds for €1,661 million (€1,644 million at December
31, 2018), of which €1,168 million (€1,147 million at December 31,
2018) related to guarantees issued towards the contractors who are
building the FLNG vessel as part of the Coral development project offshore
Mozambique; (iii) an unsecured guarantee of €499 million (€499 million
at December 31, 2018) given by Eni SpA on behalf of the participated
Saipem joint-venture to Treno Alta Velocità — TAV SpA (now RFI — Rete
Ferroviaria Italiana SpA) for the proper and timely completion of a project
for the construction of the Milan-Bologna fast track railway by the CEPAV
(Consorzio Eni per l’Alta Velocità) Uno; (iv) a guarantee issued in favor of
Gulf LNG Energy and Gulf LNG Pipeline and on behalf of Angola LNG Supply
Service Llc (Eni’s interest 13.60%) to cover contractual commitments of
paying re-gasification fees for €181 million (€177 million at December
31, 2018). At December 31, 2019, the underlying commitment issued on
behalf of joint ventures and associates covered by such guarantees was
€2,109 million (€2,159 million at December 31, 2018).
Commitments and risks
(€ milioni)
Commitments
Risks
December 31, 2019
74,338
676
75,014
December 31, 2018
54,611
673
55,284
Commitments related to: (i) parent company guarantees that were issued
in connection with certain contractual commitments for hydrocarbon
exploration and production activities and quantified, on the basis of the
capital expenditures to be incurred, to be €65,374 million (€52,397 million
at December 31, 2018). The increase of €12,977 million was incurred in
connection with: (a) the issuance of new parent company guarantees of
€9,794 million of which €8,904 million issued on behalf of Eni Abu Dhabi
BV in relation to the entry into the exploration permits of Blocks 1 and 2
and €890 million on behalf of Eni RAK BV in relation to the entry and the
start of exploration activities in block A in the United Arab Emirates. These
parent company guarantees are in addition to those issued in 2018 as part
of the transactions with the Abu Dhabi State oil company ADNOC, whereby
Eni acquired participating interests in the two offshore concessions in
production of Lower Zakum (Eni’s interest 5%) and Umm Shaif and Nasr
(Eni’s interest 10%) for a period of 40 years and a maximum amount of
€13,356 million and in the concession under development of Gasha (Eni’s
interest 25%) for a period of 40 years and a maximum amount of €22,261
million. These guarantees were issued to cover the contractual obligations
towards the State company, deriving from oil operations related to the
Concession Agreements including, in particular, the achievement of some
production targets and recovery factors of reserves in the medium and
long term, an asset integrity plan and optimization and maintenance of
the production after reaching the plateau, the transfer of technologies and
the adoption of best-in-class operating standards in HSE. The guarantees
do not cover any loss of profit or production deriving from failure to achieve
the targets; (b) a new parent company guarantee of €445 million issued
in relation to an asset swap with Lukoil involving Blocks 10 and 12 in
the offshore of Mexico. This parent company guarantee is in addition to
those issued in previous years for €9,194 million, of which €6,968 million
issued in 2018 following the awarding of new exploration licenses in the
offshore of Mexico and the final investment decision for the development
of the offshore reserves in Area 1; (c) a new parent company guarantee
for €1,781 million in relation to the acquisition of the upstream assets
of ExxonMobil by the joint venture Vår Energi AS intended to cover the
decommissioning contractual obligations; (ii) two parent company
guarantees for a total amount of €6,527 million given on behalf of Eni
Abu Dhabi Refining & Trading BV following the Share Purchase Agreement
to acquire from ADNOC a 20% equity interest in ADNOC Refining and the
set-up of ADNOC Global Trading Ltd dedicated to marketing petroleum
products. The first parent company guarantee of €2,965 million was
issued to guarantee the obligations under the Share Purchase Agreement
and will remain in place until the payment of the Deferred Consideration
expected by March 31, 2020. The second parent company guarantee
of €3,562 million has been issued to guarantee the obligations set out
in the Shareholders Agreements and will remain in force as long as the
investment is maintained; (iii) commitments assumed by Eni USA Gas
Marketing Llc towards Angola LNG Supply Service Llc for the purchase of
volumes of regasified gas at the Pascagoula plant (United States) over
a twenty-year period (until 2031). The expected commitments were
estimated at €1,978 million (€2,079 million at December 31, 2018)
and have been included in off-balance sheet contractual commitments
in the table “Future payments under contractual obligations” in the
paragraph Liquidity risk. However, since the project has been abandoned
by the partners, Eni does not expect to make any payment under those
contractual obligations. In 2018, the contractual commitment signed in
December 2007 between Eni USA Gas Marketing Llc and Gulf LNG Energy
Llc (GLE) and Gulf LNG Pipeline Llc (GLP) for the purchase of long-term
regasification and transport services (until 2031) amounting at December
31, 2017 to €948 million (undiscounted) ceased due to an arbitration
ruling. The jurors established that the commitment was resolved by March
1, 2016 and recognized to the counterparties an equitable compensation
of €324 million to Eni’s counterparties. Despite the ruling of the arbitration
court invalidating the contract, GLE and GLP filed a claim with the
Supreme Court of New York against Eni SpA demanding the enforcement
of the parent company guarantee issued by Eni for the payment of the
regasification fees until to the original due date of the contract (2031) for a
maximum amount of €757 million. Eni believes that the claims by GLE and
GLP have no merit and is defending the action. At the moment, the risk of
losing the proceeding is considered unlikely; (iv) a memorandum of intent
signed with the Basilicata Region, whereby Eni has agreed to invest €114
million (€116 million at December 31, 2018) in the future, also on account
of Shell Italia E&P SpA, in connection with Eni’s development plan of oilfields
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019
208
in Val d’Agri. The commitment has been included in the off-balance sheet
contractual commitments in the following paragraph “Liquidity risk”;
(v) the commitment of €105 million for the acquisition of a 70% stake of
Evolvere SpA, a company leader in the distributed generation of energy
from renewable sources; the acquisition was finalized in January 2020.
Risks relate to potential risks associated with (i) contractual assurances
given to acquirers of certain investments and businesses of Eni for €248
million (€244 million at December 31, 2018); (ii)assets of third parties
under the custody of Eni for €428 million (€429 million at December 31,
2018).
Other commitments and risks
A parent company guarantee was issued on behalf of Cardón IV SA (Eni’s
interest 50%), a joint venture operating the Perla gas field located in
Venezuela, for the supply to PDVSA GAS of the volumes of gas produced by
the field until end of the concession agreement (2036). This guarantee
cannot be quantified because the penalty clause for unilateral anticipated
resolution originally set for Eni and the relevant quantification became
ineffective due to a revision of the contractual terms. In case of failure
on part of the operator to deliver the contractual gas volumes out of
production, the claim under the guarantee will be determined by applying
the local legislation. Eni's share (50%) of the contractual volumes of gas
to be delivered to PDVSA GAS amounted to a total of around €13 billion.
Notwithstanding this amount does not properly represent the guarantee
exposure, nonetheless such amount represents the maximum financial
exposure at risk for Eni. A similar guarantee was issued by PDVSA on
behalf of Eni for the fulfillment of the purchase commitments of the gas
volumes by PDVSA GAS.
Other commitments also include the agreements entered into for
forestry initiatives, implemented within the low carbon strategy defined
by the Company, and in particular concerning the commitments for the
purchase, up to 2038, of carbon credits produced and certified according
to international standards by subjects specialized in forest conservation
programs.
Eni is liable for certain non-quantifiable risks related to contractual
assurances given to acquirers of certain Eni assets, including businesses
and investments, against certain contingent liabilities deriving from tax,
social security contributions, environmental issues and other matters
applicable to periods during which such assets were operated by Eni. Eni
believes such matters will not have a material adverse effect on Eni’s
results of operations and liquidity.
Financial risks
Financial risks are managed in respect of guidelines issued by
the Board of Directors of Eni SpA in its role of directing and setting
the risk limits, targeting to align and centrally coordinate Group
companies’ policies on financial risks ("Guidelines on financial risks
management and control"). The "Guidelines" define for each financial
risk the key components of the management and control process,
such as the aim of the risk management, the valuation methodology,
the structure of limits, the relationship model and the hedging and
mitigation instruments.
MARKET RISK
Market risk is the possibility that changes in currency exchange rates,
interest rates or commodity prices will adversely affect the value of
the Group’s financial assets, liabilities or expected future cash flows.
The Company actively manages market risk in accordance with a set
of policies and guidelines that provide a centralized model of handling
finance, treasury and risk management transactions based on the
Company’s departments of operational finance: the parent company’s
(Eni SpA) finance department, Eni Finance International SA, Eni Finance
USA Inc and Banque Eni SA, which is subject to certain bank regulatory
restrictions preventing the Group’s exposure to concentrations of credit
risk, and Eni Trading & Shipping that is in charge to execute certain
activities relating to commodity derivatives. In particular, Eni Corporate
finance department, Eni Finance International SA and Eni Finance USA
Inc manage subsidiaries’ financing requirements in and outside Italy
and in the United States of America, respectively, covering funding
requirements and using available surpluses. All transactions concerning
currencies and derivative contracts on interest rates and currencies
different from commodities are managed by the parent company, while
Eni Trading & Shipping SpA executes the negotiation of commodity
derivatives over the market. Eni SpA and Eni Trading & Shipping SpA
(also through its subsidiary Eni Trading & Shipping Inc) perform trading
activities in financial derivatives on external trading venues, such as
European and non-European regulated markets, Multilateral Trading
Facility (MTF), Organized Trading Facility (OTF), or similar and brokerage
platforms (i.e. SEF), and over the counter on a bilateral basis with
external counterparties. Other legal entities belonging to Eni that require
financial derivatives enter into these transactions through Eni Trading
& Shipping and Eni SpA based on the relevant asset class expertise. Eni
uses derivative financial instruments (derivatives) in order to minimize
exposure to market risks related to fluctuations in exchange rates
relating to those transactions denominated in a currency other than the
functional currency (the euro) and interest rates, as well as to optimize
exposure to commodity prices fluctuations taking into account the
currency in which commodities are quoted. Eni monitors every activity
in derivatives classified as risk-reducing (in particular, back-to-back
activities, flow hedging activities, asset-backed hedging activities and
portfolio-management activities) directly or indirectly related to covered
industrial assets, so as to effectively optimize the risk profile to which
Eni is exposed or could be exposed. If the result of the monitoring shows
those derivatives should not be considered as risk reducing, these
derivatives are reclassified in proprietary trading. As proprietary trading
is considered separately from the other activities in specific portfolios of
Eni Trading & Shipping, its exposure is subject to specific controls, both in
terms of Value at Risk (VaR) and stop loss and in terms of nominal gross
value. For Eni, the gross nominal value of proprietary trading activities
is compared with the limits set by the relevant international standards.
The framework defined by Eni’s policies and guidelines provides that
the valuation and control of market risk is performed on the basis of
maximum tolerable levels of risk exposure defined in terms of: (i) limits
of stop loss, which expresses the maximum tolerable amount of losses
associated with a certain portfolio of assets over a pre-defined time
horizon; (ii) limits of revision strategy, which consist in the triggering
of a revision process of the strategy in the event of exceeding the level
of profit and loss given; and (iii) VaR which measures the maximum
potential loss of the portfolio, given a certain confidence level and holding
period, assuming adverse changes in market variables and taking into
account the correlation among the different positions held in the portfolio.
Eni’s finance department defines the maximum tolerable levels of risk
exposure to changes in interest rates and foreign currency exchange
rates in terms of VaR, pooling Group companies’ risk positions maximizing,
when possible, the benefits of the netting activity. Eni’s calculation and
valuation techniques for interest rate and foreign currency exchange rate
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 209
risks are in accordance with banking standards, as established by the
Basel Committee for bank activities surveillance. Tolerable levels of risk are
based on a conservative approach, considering the industrial nature of the
Company. Eni’s guidelines prescribe that Eni Group companies minimize
such kinds of market risks by transferring risk exposure to the parent
company finance department. Eni’s guidelines define rules to manage the
commodity risk aiming at optimizing core activities and pursuing preset
targets of stabilizing industrial and commercial margins. The maximum
tolerable level of risk exposure is defined in terms of VaR, limits of revision
strategy, stop loss and volumes in connection with exposure deriving
from commercial activities, as well as exposure deriving from proprietary
trading, exclusively managed by Eni Trading & Shipping. Internal mandates
to manage the commodity risk provide for a mechanism of allocation
of the Group maximum tolerable risk level to each business unit. In this
framework, Eni Trading & Shipping, in addition to managing risk exposure
associated with its own commercial activity and proprietary trading, pools
the requests for negotiating commodity derivatives and executes them in
the marketplace. According to the targets of financial structure included
in the financial plan approved by the Board of Directors, Eni decided to
retain a cash reserve to face any extraordinary requirement. Eni’s finance
department, with the aim of optimizing the efficiency and ensuring
maximum protection of capital, manages such reserve and its immediate
liquidity within the limits assigned. The management of strategic cash is
part of the asset management pursued through transactions on own risk
in view of optimizing financial returns, while respecting authorized risk
levels, safeguarding the Company’s assets and retaining quick access to
liquidity.
The four different market risks, whose management and control have been
summarized above, are described below.
MARKET RISK - EXCHANGE RATE
Exchange rate risk derives from the fact that Eni’s operations
are conducted in currencies other than euro (mainly US dollar).
Revenues and expenses denominated in foreign currencies
may be significantly affected by exchange rate fluctuations
due to conversion differences on single transactions arising
from the time lag existing between execution and definition of
relevant contractual terms (economic risk) and conversion of
foreign currency-denominated trade and financing payables and
receivables (transactional risk). Exchange rate fluctuations affect
the Group’s reported results and net equity as financial statements
of subsidiaries denominated in currencies other than euro are
translated from their functional currency into euro. Generally, an
appreciation of US dollar versus euro has a positive impact on Eni’s
results of operations, and vice versa. Eni’s foreign exchange risk
management policy is to minimize transactional exposures arising
from foreign currency movements and to optimize exposures
arising from commodity risk. Eni does not undertake any hedging
activity for risks deriving from the translation of foreign currency
denominated profits or assets and liabilities of subsidiaries, which
prepare financial statements in a currency other than euro, except
for single transactions to be evaluated on a case-by-case basis.
Effective management of exchange rate risk is performed within
Eni’s finance departments, which pool Group companies’ positions,
hedging the Group net exposure by using certain derivatives,
such as currency swaps, forwards and options. Such derivatives
are evaluated at fair value based on market prices provided by
specialized info-providers. Changes in fair value of those derivatives
are normally recognized through profit and loss, as they do not meet
the formal criteria to be recognized as hedges. The VaR techniques
are based on variance/covariance simulation models and are used
to monitor the risk exposure arising from possible future changes in
market values over a 24-hour period within a 99% confidence level
and a 20-day holding period.
MARKET RISK - INTEREST RATE
Changes in interest rates affect the market value of financial assets and
liabilities of the Company and the level of finance charges. Eni’s interest
rate risk management policy is to minimize risk with the aim to achieve
financial structure objectives defined and approved in management’s
finance plans. The Group’s finance departments pool borrowing
requirements of the Group companies in order to manage net positions
and fund portfolio developments consistent with management plans,
thereby maintaining a level of risk exposure within prescribed limits. Eni
enters into interest rate derivative transactions, in particular interest rate
swaps, to manage effectively the balance between fixed and floating
rate debt. Such derivatives are evaluated at fair value based on market
prices provided from specialized sources. VaR deriving from interest rate
exposure is measured daily based on a variance/covariance model, with a
99% confidence level and a 20-day holding period.
MARKET RISK - COMMODITY
Eni’s results of operations are affected by changes in the prices of
commodities. A decrease in Oil & Gas prices generally has a negative
impact on Eni’s results of operations and vice versa, and may jeopardize
the achievement of the financial targets preset in the Company’s four-year
plans and budget. The commodity price risk arises in connection with the
following exposures: (i) strategic exposure: exposures directly identified
by the Board of Directors as a result of strategic investment decisions
or outside the planning horizon of risk. These exposures include those
associated with the program for the production of proved and unproved
Oil & Gas reserves, long-term gas supply contracts for the portion not
balanced by ongoing or highly probable sale contracts, refining margins
identified by the Board of Directors of strategic nature (the remaining
volumes can be allocated to the active management of the margin or to
asset-backed hedging activities) and minimum compulsory stocks; (ii)
commercial exposure: includes the exposures related to the components
underlying the contractual arrangements of industrial and commercial
activities and, if related to take-or-pay commitments, to the components
related to the time horizon of the four-year plan and budget and the
relevant activities of risk management. Commercial exposures are
characterized by a systematic risk management activity conducted based
on risk/return assumptions by implementing one or more strategies and
subjected to specific risk limits (VaR, revision strategy limits and stop
loss). In particular, the commercial exposures include exposures subjected
to asset-backed hedging activities, arising from the flexibility/optionality
of assets; and (iii) proprietary trading exposure: includes operations
independently conducted for profit purposes in the short term, and
normally not for the purpose of delivery, both within the commodity and
financial markets, with the aim to obtain a profit upon the occurrence of a
favorable result in the market, in accordance with specific limits
of authorized risk (VaR, stop loss). Origination activities are included in
the proprietary trading exposures, if not connected to contractual
or physical assets.
Strategic risk is not subject to systematic activity of management/
coverage that is eventually carried out only in case of specific market
or business conditions. Because of the extraordinary nature, hedging
activities related to strategic risks are delegated to the top management.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019 210
Strategic risk is subject to measuring and monitoring but is not subject
to specific risk limits. If previously authorized by the Board of Directors,
exposures related to strategic risk can be used in combination with
other commercial exposures in order to exploit opportunities for natural
compensation between the risks (natural hedge) and consequently
reduce the use of derivatives (by activating logics of internal market).
Eni manages exposure to commodity price risk arising in normal trading
and commercial activities in view of achieving stable economic results.
Eni manages the commodity risk through the trading unit of Eni Trading
& Shipping and the exposure to commodity prices through the Group’s
finance departments by using derivatives traded on the organized
markets MTF, OTF and derivatives traded over the counter (swaps, forward,
contracts for differences and options on commodities) with the underlying
commodities being crude oil, gas, refined products, power or emission
certificates. Such derivatives are valued at fair value based on market
prices provided from specialized sources or, absent market prices, on the
basis of estimates provided by brokers or suitable valuation techniques.
VaR deriving from commodity exposure is measured daily based on a
historical simulation technique, with a 95% confidence level and a one-day
holding period.
MARKET RISK - STRATEGIC LIQUIDITY
Market risk deriving from liquidity management is identified as the
possibility that changes in prices of financial instruments (bonds,
money market instruments and mutual funds) would affect the
value of these instruments when valued at fair value. The setting
up and maintenance of the liquidity reserve is mainly aimed to
guarantee a proper financial flexibility. Liquidity should allow Eni to
fund any extraordinary need (such as difficulty in access to credit,
exogenous shock, macroeconomic environment, as well as merger
and acquisitions) and must be dimensioned to provide a coverage of
short-term debts and a coverage of medium and long-term finance
debts due within a time horizon of 24 months. In order to manage the
investment activity of the strategic liquidity, Eni defined a specific
investment policy with aims and constraints in terms of financial
activities and operational boundaries, as well as Governance guidelines
regulating management and control systems. In particular, strategic
liquidity management is regulated in terms of VaR (measured based
on a parametrical methodology with a one-day holding period and
a 99% confidence level), stop loss and other operating limits in
terms of concentration, issuing entity, business segment, Country
of emission, duration, ratings and type of investing instruments in
portfolio, aimed to minimize market and liquidity risks. Financial
leverage or short selling is not allowed. Activities in terms of strategic
liquidity management started in the second half of the year 2013
(Euro portfolio) and throughout the course of the year 2017 (US dollar
portfolio). In 2019, the Euro investment portfolio has maintained an
average credit rating of A-/BBB+, whereas the USD investment portfolio
has maintained an average credit rating of A+/A, both in line with the
year 2018. The following tables show amounts in terms of VaR, recorded
in 2019 (compared with 2018) relating to interest rate and exchange
rate risks in the first section and commodity risk. Regarding the
management of strategic liquidity, the sensitivity to changes of interest
rate is expressed by values of “Dollar value per Basis Point” (DVBP).
(Value at risk - parametric method variance/covariance; holding period: 20 days; confidence level: 99%)
(€ million)
Interest rate(a)
Exchange rate(a)
High
5.19
0.41
2019
Low Average
3.80
2.44
0.17
0.07
At year end
3.00
0.15
High
3.65
0.57
2018
Low Average
2.73
1.80
0.28
0.09
At year end
2.99
0.25
(a) Value at risk deriving from interest and exchange rates exposures include the following finance departments: Eni Corporate Finance Department, Eni Finance International SA, Banque Eni SA and Eni
Finance USA Inc.
(Value at risk - Historic simulation method; holding period: 1 day; confidence level: 95%)
(€ million)
Commercial exposures - Management Portfolio(a)
Trading(b)
High
23.03
1.60
2019
Low Average
11.22
7.74
0.51
0.25
At year end
9.11
0.31
High
18.60
2.28
2018
Low Average
11.04
6.79
0.73
0.26
At year end
7.50
0.27
(a) Refers to the LNG Marketing & Power business line (risk exposure from Refining & Marketing business line and Gas & Power Division), Eni Trading & Shipping commercial portfolio, operating branches
outside Italy pertaining to the Divisions and from October 2016 the Gas e Luce business line. For the Gas & Power business lines, following the approval of the Eni’s Board of Directors on December 12,
2013, VaR is calculated on the so-called Statutory view, with a time horizon that coincides with the year considering all the volumes delivered in the year and the relevant financial hedging derivatives.
Consequently, during the year the VaR pertaining to GLP and EGL presents a decreasing trend following the progressive reaching of the maturity of the positions within the annual horizon.
(b) Cross-commodity proprietary trading, both for commodity contracts and financial derivatives, refers to Eni Trading & Shipping SpA (London-Bruxelles-Singapore) and Eni Trading & Shipping Inc (Houston).
(Sensitivity - Dollar value of 1 basis point - DVBP)
(€ million)
Strategic liquidity(a)
High
0.37
2019
Low Average
0.35
0.31
At year end
0.33
High
0.35
2018
Low Average
0.29
0.25
At year end
0.25
(a) Management of strategic liquidity portfolio in € currency starting from July 2013.
(Sensitivity - Dollar value of 1 basis point - DVBP)
($ million)
Strategic liquidity(b)
High
0.05
2019
Low Average
0.04
0.02
At year end
0.05
High
0.04
2018
Low Average
0.02
0.01
At year end
0.02
(b) Management of strategic liquidity portfolio in $ currency starting from August 2017.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 211
CREDIT RISK
Credit risk is the potential exposure of the Group to losses in case
counterparties fail to perform or pay amounts due. Eni defined
credit risk management policies consistent with the nature and
characteristics of the counterparties of commercial and financial
transactions with regard to the centralized finance model.
The Company adopted a model to quantify and control the credit risk
based on the evaluation of the expected loss which represents the
probability of default and the capacity to recover credits in default that
is estimated through the so-called Loss Given Default.
In the credit risk management and control model, credit exposures
are distinguished by commercial nature, in relation to the structured
contracts on commodities related to Eni's core business, and by
financial nature, in relation to the financial instruments substantially
used by Eni, such as deposits, derivatives and securities.
Credit risk for commercial exposures
Credit risk arising from commercial counterparties is managed by
the business units and by the specialized corporate finance and
administration departments, and is operated on the basis of formal
procedures for the assessment and assignment of commercial
counterparties, the monitoring of credit exposures, credit recovery
activities and disputes. At a corporate level, the general guidelines and
methods for quantifying and controlling customer risk, in particular for
commercial counterparties, are assessed through an internal rating
model that combines different default factors deriving from economic
variables, financial indicators, payment experiences and information
from primary info providers. The probability of default related to
State Entities or their closely related counterparties (e.g. National
Oil Company), essentially represented by the probability of late
payments, is determined by using the Country risk premiums adopted
for the purposes of the determination of the WACCs for the impairment
of non-financial assets. Furthermore, for retail positions without
specific ratings, risk is determined by distinguishing customers in
homogeneous risk clusters based on historical series of data relating
to payments, periodically updated.
Credit risk for financial exposures
With regard to credit risk arising from financial counterparties
deriving from current and strategic use of liquidity, derivative
contracts and transactions with underlying financial assets valued
at fair value, Eni has established internal policies providing exposure
control and concentration through maximum credit risk limits
corresponding to different classes of financial counterparties as
defined by the Company’s Board of Directors taking into account
the credit ratings provided by primary credit rating agencies on
the marketplace. Credit risk arising from financial counterparties
is managed by the Eni’s operating finance departments and Eni’s
subsidiary Eni Trading & Shipping which specifically engages in
commodity derivatives transactions and by Group companies
and business units, only in the case of physical transactions with
financial counterparties consistently with the Group centralized
finance model. Eligible financial counterparties are closely monitored
by each counterpart and by group of belonging to check exposures
against the limits assigned on a daily basis and the expected loss
analysis and the concentration periodically.
LIQUIDITY RISK
Liquidity risk is the risk that suitable sources of funding for the Group
may not be available, or the Group is unable to sell its assets in the
marketplace in order to meet short-term finance requirements and
to settle obligations. Such a situation would negatively affect Group
results, as it would result in the Company incurring higher borrowing
expenses to meet its obligations or under the worst of conditions the
inability of the Company to continue as a going concern. Eni's risk
management targets include the maintaining of an adequate level of
liquidity readily available to deal with external shocks (drastic changes
in the scenario, restrictions on access to capital markets, etc.) or to
ensure an adequate level of operational flexibility for the development
programs of the Company. The strategic liquidity reserve is employed
in short-term marketable financial instruments, favouring investments
with very low risk profile.
At present, the Group believes to have access to sufficient funding
to meet the current foreseeable borrowing requirements as a
consequence of the availability of financial assets and lines of credit
and the access to a wide range of funding at competitive costs through
the credit system and capital markets.
Eni has in place a program for the issuance of Euro Medium Term
Notes up to €20 billion, of which about €14.9 billion were drawn as of
December 31, 2019.
The Group has credit ratings of A- outlook stable and A-2, respectively
for long and short-term debt, assigned by Standard & Poor’s; Baa1
outlook stable and P-2, respectively for long and short-term debt,
assigned by Moody’s; A- outlook stable and F1, respectively for long
and short-term debt, assigned by Fitch. Eni’s credit rating is linked in
addition to the Company’s industrial fundamentals and trends in the
trading environment to the sovereign credit rating of Italy. Based on
the methodologies used by the credit rating agencies, a downgrade
of Italy’s credit rating may trigger a potential knock-on effect on the
credit rating of Italian issuers such as Eni. During 2019, the rating of
Eni remained unchanged.
In 2019, Eni issued bonds for €1,635 million, of which €746 million as
part of the Euro Medium Term Notes program and €889 million through
an issue amounting to $1 billion in the US and international markets.
As of December 31, 2019, Eni maintained short-term unused borrowing
facilities of €13,299 million. Long-term committed unused borrowing
facilities amounted to €4,667 million, of which €450 million due within
12 months. These facilities bore interest rates and fees for unused
facilities that reflected prevailing market conditions.
Expected payments for finance debts and lease liabilities
The tables below summarize the Group main contractual obligations
for finance debt and lease liability repayments, including expected
payments for interest charges and derivatives.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019 212
(€ million)
December 31, 2019
Non-current financial liabilities (including the current portion)
Current financial liabilities
Lease liabilities
Fair value of derivative instruments
Interest on finance debt
Interest on lease liabilities
Financial guarantees
December 31, 2018
Non-current financial liabilities (including the current portion)
Current financial liabilities
Fair value of derivative instruments
Interest on finance debt
Financial guarantees
Maturity year
2020
2021
2022
2023
2024
2025 and
thereafter
2,908
2,452
884
2,704
8,948
594
341
935
926
1,704
1,259
2,743
1,785
11,521
632
2
2,338
452
302
754
487
14
1,760
353
263
616
434
424
3,177
342
233
575
2,209
269
206
475
2,761
34
14,316
1,667
1,015
2,682
Maturity year
2019
2020
2021
2022
2023
2024 and
thereafter
3,301
2,182
1,445
6,928
655
668
2,958
1,541
1,253
2,714
11,723
13
2,971
545
1
1,542
436
21
1,274
330
2,714
320
5
11,728
1,677
Liabilities for leased assets including interest for €2,953 million
to the share pertaining to the partners of unincorporated joint
operations operated by Eni which will be recovered through
recharges of cash calls.
Expected payments for trade and other payables
(€ million)
December 31, 2019
Trade payables
Other payables and advances
December 31, 2018
Trade payables
Other payables and advances
Maturity year
2020
2021-2024
2025 and
thereafter
10,480
5,065
15,545
54
54
100
100
Maturity year
2019
2020 - 2023
2024 and
thereafter
11,645
5,102
16,747
59
59
96
96
Total
21,920
2,452
5,622
2,754
32,748
3,677
2,360
6,037
926
Total
23,490
2,182
1,485
27,157
3,963
668
Total
10,479
5,219
15,698
Total
11,645
5,257
16,902
Expected payments under contractual obligations37
In addition to lease, financial, trade and other liabilities represented
in the balance sheet, the Company is subject to non-cancellable
contractual obligations or obligations, the cancellation of which
requires the payment of a penalty. These obligations will require
cash settlements in future reporting periods. These liabilities
are valued based on the net cost for the Company to fulfill the
contract, which consists of the lowest amount between the costs
for the fulfillment of the contractual obligation and the contractual
compensation/penalty in the event of non-performance.
The Company’s main contractual obligations at the balance sheet
date comprise take-or-pay clauses contained in the Company’s gas
supply contracts or shipping arrangements, whereby the Company
obligations consist of off-taking minimum quantities of product
or service or, in case of failure, paying the corresponding cash
amount that entitles the Company the right to collect the product
or the service in future years. Future obligations in connection
with these contracts were calculated by applying the forecasted
prices of energy or services included in the four-year business plan
approved by the Company’s Board of Directors.
The table below summarizes the Group principal contractual obligations
as of the balance sheet date, shown on an undiscounted basis.
(37) Contractual obligations related to employee benefits are indicated in note 21 - Provisions for employee benefits.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
213
(€ million)
Decommissioning liabilities(a)
Environmental liabilities
Purchase obligations(b)
- Gas
. take-or-pay contracts
. ship-or-pay contracts
- Other purchase obligations
Other obligations
- Memorandum of intent - Val d’Agri
Total
2020
331
403
9,938
7,117
1,070
1,751
7
7
10,679
2021
325
368
9,912
9,140
532
240
1
1
10,606
Maturity year
2022
163
319
9,467
8,912
454
101
2023
179
238
9,530
9,100
412
18
2024
424
198
9,722
9,410
296
16
9,949
9,947
10,344
2025 and
thereafter
12,052
1,065
77,914
77,239
646
29
106
106
91,137
Total
13,474
2,591
126,483
120,918
3,410
2,155
114
114
142,662
(a) Represents the estimated future costs for the decommissioning of oil and natural gas production facilities at the end of the producing lives of fields, well-plugging, abandonment and site restoration.
(b) Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms.
Capital investment and capital expenditure commitments
In the next four years, Eni expects capital investments and capital
expenditures of €31.5 billion. The table below summarizes Eni’s capital
expenditure commitments for property, plant and equipment and
capital projects. Capital expenditure is considered to be committed
when the project has received the appropriate level of internal
management approval. At this stage, procurement contracts to execute
those projects have already been awarded or are being awarded to
third parties.
The amounts shown in the table below include committed expenditures
to execute certain environmental projects.
(€ million)
Committed projects
Maturity year
2020
5,570
2021
4,054
2022
2,611
2023
1,544
2024 and
thereafter
2,669
Total
16,448
Other information about financial instruments
The carrying amount of financial instruments and the relevant economic and equity effect consisted of the following:
(€ million)
Financial instruments at fair value with effects recognized
in profit and loss acount
Financial assets held for trading(a)
Non-hedging and trading derivatives(b)
Other investments valued at fair value(c)
Receivables and payables and other assets/liabilities valued
at amortized cost
Trade receivables and other(d)
Financing receivables(e)
Securities(a)
Trade payables and other(a)
Financing payables(f)
Net assets (liabilities) for hedging derivatives(g)
2019
Finance income (expense)
recognized in
2018
Finance income (expense)
recognized in
Carrying
amount
Profit and loss
account
Other
comprehensive
income
Carrying
amount
Profit and loss
account
Other
comprehensive
income
6,760
(125)
929
12,926
1,503
55
15,699
24,518
(2)
127
273
247
(409)
110
33
(802)
(739)
6,552
177
919
14,145
1,489
64
16,902
25,865
(3)
(679)
32
(178)
231
(343)
(139)
(28)
(615)
642
15
(243)
(a) Income or expense were recognized in the profit and loss account within "Finance income (expense)".
(b) In the profit and loss account, economic effects were recognized as income within "Other operating income (loss)" for €287 million (income for €129 million in 2018) and as loss within "Finance
income (expense)" for €14 million (loss for €307 million in 2018).
(c) Income or expense were recognized in the profit and loss account within "Income (expense) from investments - Dividends".
(d) Income or expense were recognized in the profit and loss account as net impairment losses within "Net (impairment losses) reversal of trade and other receivables" for €432 million (net
impairment losses for €415 million in 2018) and as income within "Finance income (expense)" for €23 million (income for €69 million in 2018), including interest income calculated on the basis of
the effective interest rate of €26 million (interest income for €38 million in 2018).
(e) In the profit and loss account, income or expense were recognized as income within "Finance income (expense)", including interest income calculated on the basis of the effective interest rate of
€99 million (income for €129 million in 2018) and net revaluations for €4 million (net impairment losses for €275 million in 2018).
(f) In the profit and loss account, income or expense were recognized as expense within "Finance income (expense)", including interest expense calculated on the basis of the effective interest rate
of €647 million (interest expense for €605 million in 2018).
(g) In the profit and loss account, income or expense were recognized within "Sales from operations" and "Purchase, services and other".
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214
Disclosures about the offsetting of financial instruments
(€ million)
December 31, 2019
Financial assets
Trade and other receivables
Other current assets
Financial liabilities
Trade and other liabilities
Other current liabilities
December 31, 2018
Financial assets
Trade and other receivables
Other current assets
Financial liabilities
Trade and other liabilities
Other current liabilities
Gross amount of financial
assets and liabilities
Gross amount of financial
assets and liabilities subject
to offsetting
Net amount of financial
assets and liabilities
13,773
4,584
16,445
7,758
15,634
4,455
18,280
7,048
900
612
900
612
1,533
1,636
1,533
1,636
12,873
3,972
15,545
7,146
14,101
2,819
16,747
5,412
The offsetting of financial assets and liabilities related to the
offsetting of: (i) receivables and payables pertaining to the
Exploration & Production segment towards state entities for
€713 million (€1,347 million at December 31, 2018) and trade
receivables and trade payables pertaining to Eni Trading &
Shipping Inc for €187 million (€186 million at December 31, 2018);
and (ii) other assets and liabilities for current financial derivatives
of €612 million (€1,636 million at December 31, 2018).
Legal Proceedings
Eni is a party in a number of civil actions and administrative arbitral
and other judicial proceedings arising in the ordinary course of
business. Based on information available to date, and taking
into account the existing risk provisions disclosed in note 20 –
Provisions and that in some instances it is not possible to make
a reliable estimate of contingency losses, Eni believes that the
foregoing will likely not have a material adverse effect on the Group
Consolidated Financial Statements.
In addition to proceedings arising in the ordinary course of
business referred to above, Eni is party to other proceedings, and a
description of the most significant proceedings currently pending
is provided in the following paragraphs. Unless otherwise indicated,
no provisions have been made for these legal proceedings as Eni
believes that negative outcomes are not probable or because the
amount of the provision cannot be estimated reliably.
1. Environment, health and safety
1.1. Criminal proceedings in the matters of environment,
health and safety
– Proceeding about the industrial site of Crotone. In 2010
a criminal proceeding started before the Public Prosecutor
of Crotone relating to allegations of environmental disaster,
poisoning of substances used in the food chain and omitted
clean-up due to the activity at a landfill site which was taken
over by Eni in 1991. Subsequently to Eni’s takeover, any
activity for waste conferral was stopped. The defendants
are certain managers of Eni Group companies, that have
managed the landfill since 1991. The Municipality of Crotone
is acting as plaintiff. In March 2019, the public prosecutor
requested the acquittal of all defendants. The proceeding
is ongoing. In April 2017, the Public Prosecutor of Crotone
started another criminal proceeding concerning the clean-up
of the area called "Farina Trappeto". The Company presented
a new clean-up program already deemed approvable by the
Ministry for the Environment. Clean-up remediation activities
have started. The Company has requested the dismissal of
the second proceeding.
(ii) Eni Rewind SpA (former Syndial SpA) and Versalis SpA
– Porto Torres – Prosecuting body: Public Prosecutor
of Sassari. In 2011, the Public Prosecutor of Sassari
(Sardinia) determined that a manager responsible for plant
operations at the site of Porto Torres should stand trial
for alleged environmental disaster and poisoning of water
and substances destined for food. The Province of Sassari,
the Municipality of Porto Torres and other entities have
been involved in the proceedings as civil parties seeking
damages. In 2013, the Prosecutor of Sassari requested a
new indictment for negligent behavior, replacing the previous
allegation of willful conduct. The Third Instance Court has
denied a motion to terminate the proceedings. The Public
Prosecutor has re-submitted request that the defendants
stand trial. The proceeding is underway.
(iii) Eni Rewind SpA (former Syndial SpA) and Versalis SpA –
(i)
Eni Rewind SpA (former Syndial SpA) (company
incorporating EniChem Agricoltura SpA – Agricoltura SpA in
liquidation – EniChem Augusta Industriale Srl – Fosfotec Srl)
Porto Torres dock. In 2012, following a request of the Public
Prosecutor of Sassari, an Italian court ordered presentation
of evidence relating to the functioning of the hydraulic
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215
barrier of Porto Torres site (ran by Eni Rewind SpA) and its
capacity to avoid the dispersion of contamination released
by the site into the nearby sea. Eni Rewind SpA and Versalis
SpA were notified that its chief executive officers and
certain other managers were being investigated. The Public
Prosecutor of the Municipality of Sassari requested that
these individuals stand trial. The plaintiffs, the Ministry for
Environment and the Sardinia Region claimed environmental
damage in an amount of €1.5 billion. Other parties referred to
the judge's equitable assessment. At a hearing in July 2016,
the court acquitted all defendants of Eni Rewind and Versalis
with respect to the crimes of environmental disaster. Three
Eni Rewind managers were found guilty of environmental
disaster relating to the period limited to August 2010 –
January 2011 and sentenced to one-year prison, with a
suspended sentence. Eni Rewind filed an appeal against this
decision. The proceeding is underway.
(iv) Eni Rewind SpA (former Syndial SpA) – The illegal landfill
in Minciaredda area, Porto Torres site. The Court of Sassari,
on request of the Public Prosecutor, seized the Minciaredda
landfill area, near the western border of the Porto Torres
site (Minciaredda area). All the indicted have been served
a notice of investigation for alleged crimes of carrying out
illegal waste disposal and environmental disaster. The seizure
order involved also Eni Rewind pursuant to Legislative
Decree No. 231/01, whereby companies are liable for the
crimes committed by their employees when performing their
duties. The court determined that Eni Rewind can be sued
for civil liability and resolved that all defendants and the Eni
subsidiary be put on trial before the Court of Sassari.
(v) Eni Rewind SpA (former Syndial SpA) – The Phosphate
deposit at Porto Torres site (1). In 2015, the Court of Sassari,
accepting a request of the Public Prosecutor of Sassari, seized
– as a preventive measure – the area of “Palte Fosfatiche”
(phosphates deposit) located on the territory of Porto Torres
site, in relation to alleged crimes of environmental disaster,
carrying out of unauthorized disposal of hazardous wastes
and other environmental crimes. Eni Rewind SpA is being
investigated pursuant to Legislative Decree No. 231/01. In
November 2019, a request for referral to trial was served on
the Eni subsidiary.
(vi) Eni Rewind SpA (former Syndial SpA) – Phosphate deposit at
Porto Torres site (2). In 2015, the Public Prosecutor at the Court
of Sassari seized – as a probative measure – the containment
systems for the meteoric waters in the area “Palte Fosfatiche”
(phosphates deposit), located on the territory of Porto Torres
site. The indicted have also been served a notice of investigation
for alleged crimes of omitted clean-up and management of
radioactive waste. This investigation has been combined into the
abovementioned one.
(vii) Eni Rewind SpA (former Syndial SpA) – Proceeding relating
to the asbestos at the Ravenna site. A criminal proceeding
is pending before the Tribunal of Ravenna relating to the
crimes of culpable manslaughter, injuries and environmental
disaster, which have been allegedly committed by former
Eni Rewind employees at the site of Ravenna. The site was
acquired by Eni Rewind following a number of corporate
mergers and acquisitions. The alleged crimes date back to
1991. In the proceeding there are 75 alleged victims. The
plaintiffs include relatives of the alleged victims, various local
administrations, and other institutional bodies, including local
trade unions. Eni Rewind asserted the statute of limitation as
a defense to the instance of environmental disaster for certain
instances of diseases and deaths. The court at Ravenna
decided that all defendants would stand trial and held that
the statute of limitation only applied with reference to certain
instances of crime of culpable injury. Eni Rewind reached
some settlements. In November 2016, the Judge acquitted
the defendants in all the contested cases except for one,
an asbestos case, for which a conviction was handed down.
The defendants, the Prosecutor and the plaintiffs appealed
the decision. The second instance Judge ordered a complex
report, and stated that they could not decide the appeal at that
stage of the proceedings, and appointed three experts. The
proceeding is ongoing before the appeals Court.
(viii) Raffineria di Gela SpA and Eni Mediterranea Idrocarburi
SpA – Alleged environmental disaster. A criminal proceeding
is pending in relation to crimes allegedly committed by the
managers of the Raffineria di Gela SpA and EniMed SpA relating
to environmental disaster, unauthorized waste disposal and
unauthorized spill of industrial wastewater. The Gela Refinery
has been prosecuted for administrative offence pursuant to
Legislative Decree No. 231/01. This criminal proceeding initially
regarded soil pollution allegedly caused by spills from 14 tanks
of the refinery storage, which had not been provided with double
bottoms, and pollution of the sea water near the coastal area
adjacent to the site due to the failure of the barrier system
implemented as part of the clean-up activities conducted at
the site. At the closing of the preliminary investigation, the
Public Prosecutor of Gela merged into this proceeding the other
investigations related to the pollution that occurred at the
other sites of the Gela refinery as well as hydrocarbon spills at
facilities of EniMed. The proceeding is ongoing.
(ix) Val d’Agri. In March 2016, the Public Prosecutors of Potenza
started a criminal investigation into alleged illegal handling
of waste material produced at the Viggiano oil center (COVA),
part of the Eni-operated Val d’Agri oil complex. After a
two-year investigation, the Prosecutors ordered the house
arrest of 5 Eni employees and the seizure of certain plants
functional to the production activity of the Val d’Agri complex
which, consequently, was shut down (loss of 60 KBOE/d
net to Eni). From the commencement of the investigation,
Eni has carried out several technical and environmental
surveys, with the support of independent experts of
international standing, who found a full compliance of the
plant and the industrial process with the requirements
of the applicable laws, as well as with best available
technologies and international best practices. The Company
implemented certain corrective measures to upgrade plants
which were intended to address the claims made by the
Public Prosecutor about an alleged operation of blending
which would have occurred during normal plant functioning.
Those corrective measures were favorably reviewed by
the Public Prosecutor. The Company restarted the plant in
August 2016. In relation to the criminal proceeding, the
Public Prosecutor’s Office requested the indictment of all
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019 216
the defendants and the Company. The Prosecutor requested
Eni and all the defendants be put on trial, pursuant to
Legislative Decree No. 231/01. The trial started in November
2017 and is ongoing.
Public Prosecutor requested one of those employees to be put
on trial with expedited proceeding, accepted by the Judge for
preliminary investigations.
(xii) Raffineria di Gela SpA and Eni Mediterranea Idrocarburi
(x) Eni SpA – Health investigation related to the COVA center.
Beside the criminal proceeding for illegal trafficking of waste,
the Public Prosecutor started another investigation in relation
to alleged health violations. The Public Prosecutor requested the
formal opening of an investigation with respect to nine people
in relation to alleged violations of the rules providing for the
preparation of a Risk Assessment Document of the working
conditions at the Val d’Agri Oil Center (COVA). In March 2017,
following the request of the Consultant of the Prosecutor,
the Labor Inspectorate of Potenza issued a fine against the
employers of the COVA for omitted and incomplete assessment
of the chemical risks for the COVA center. In October 2017, the
Prosecutor’s Office changed the criminal allegations to disaster,
murder and negligent personal injury, also alleging breaches of
health and safety regulations. The proceeding is ongoing.
SpA – Waste management of the landfill Camastra. In June
2018, the Public Prosecutor of Palermo (Sicily) notified Eni’s
subsidiaries Raffineria di Gela SpA and Eni Mediterranea
Idrocarburi SpA of a criminal proceeding relating to allegations
of unlawful disposal of industrial waste resulting from the
reclaiming activities of soil, which were discharged at a
landfill owned by a third party. The Prosecutor charged the
then chief executive officers of the two subsidiaries, and the
legal entities have been charged with the liability pursuant to
Legislative Decree No. 231/01. The alleged wrongdoing related
to the willful falsification of the waste certification for purpose
of discharging at the landfill. The charge against the CEO of
the Refinery of Gela SpA and of the company itself has been
dismissed, while the CEO of Enimed SpA and the company
were requested to be put on trial. The proceeding is ongoing.
(xi) Proceeding Val d’Agri – Tank spill. In February 2017, the
(xiii) Eni Rewind SpA (former Syndial SpA) - Environmental
Italian police department of Potenza found a stream of water
contaminated by hydrocarbon traces of unknown origin, flowing
inside a small shaft located outside the COVA. Eni carried out
activities at the COVA aimed at determining the origin of the
contamination and identified the cause in a failure of a tank
outside of the COVA, that presented a risk — currently averted
— of extension of the contamination in the downstream area
of the plant. In executing these activities, Eni performed all the
communications provided for by Legislative Decree 152/06 and
started certain emergency safe-keeping operations at the areas
subject to potential contamination outside the COVA. Furthermore,
the Company completed the arrangement plan for the internal and
external areas of the COVA, whose final report was examined by the
relevant authorities. Following this event, a criminal investigation
was initiated in order to ascertain whether there had been illegal
environmental pollution by the former COVA officers, the Operation
Managers in charge since 2011 and the HSE Manager in charge
at the time of the accident, and also against Eni in relation to
the same offense pursuant to Legislative Decree No. 231/01 as
communicated in December 2018 following the notification of
the extension of the terms for preliminary investigations and of
some public officials belonging to local administrations for official
misconduct, false and fraudulent public statements committed in
2014 and of the crime for environmental disaster and of culpable
conduct committed in February 2017. Investigations are ongoing.
The Company has paid damages of an immaterial amount to
certain landlords of areas close to the COVA, which were affected
by a spillover. Discussions are ongoing with other claimants. The
likely disbursements relating to these transactions have been
provisioned. In February 2018, Eni contested the reports presented
in October and in December 2017 by the Italian Fire Department
stating that it does not consider itself obliged to carry out the
integration required, considering that the data acquired in the area
affected by the event indicate, according to Eni’s assessments, that
the loss was promptly and efficiently controlled and there were no
situations of serious danger to human health and the environment.
In April 2019, precautionary measures were ordered against
three Eni employees at the COVA. In September 2019, the
disaster at Ferrandina. In January 2018, the Public Prosecutor
of Matera commenced a criminal proceeding against a
manager of the Eni subsidiary Eni Rewind based on allegations
of unlawful handling of waste and environmental disaster as
part of the reclaiming activities performed at an industrial
site (Ferrandina/Pisticci in the south of Italy). The charge
related to an alleged spillover of effluent in the subsoil and
then in a nearby river due to a damaged pipe dedicated to the
transportation of effluent to a disposal plant owned by a third
party. At the preliminary hearing in October 2019, the Judge
dismissed the case on the basis that the defendant did not
commit any crime.
(xiv) Versalis SpA - Preventive seizure at the Priolo Gargallo plant.
In February 2019, the Court of Syracuse at the request of the
Public Prosecutor ordered the seizure of the Priolo/Gargallo
plant as part of an ongoing investigation concerning the
offenses of dangerous disposal of materials and environmental
pollution, by the former plant manager of Versalis, pursuant to
Legislative Decree No. 231/01. The Public Prosecutor's thesis,
according to the consultants, is that the plants covered by the
provision have points of emissions that do not comply with the
Best Available Techniques (BAT), therefore resulting in violation
of the applicable legislation. Versalis has already implemented
certain plant upgrades designed to comply with measures
requested by the Public Prosecutor and his consultants.
Based on this, an appeal was filed against the measure of
precautionary seizure of the plant before a Review Court, which
revoked the seizure of the plants on March 26, 2019.
(xv) Eni SpA – Fatal accident Ancona offshore platform. On March
5, 2019, a fatal accident occurred at the Barbara F platform
in the offshore of Ancona. During the unloading phase of
a tank from the platform to a supply vessel, there was a
sudden failure of a part of the structure on which a crane
was installed, causing the death of an Eni employee who
was inside the control cabin of the crane and injuries to two
other workers. The Public Prosecutor of Ancona opened an
investigation against unknown persons and ordered further
technical appraisals relating to the crane. As part of the
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
217
technical assessment of the incident, the Public Prosecutor
resolved to put under investigation the Eni employees who
were in charge of safety standards at the involved facility.
Also the Company has been put under investigation pursuant
to Legislative Decree No. 231/01, which holds companies
liable for the crimes committed by employees in a number of
matters, including the violations of laws about safety of the
workplace. The proceeding is ongoing.
(xvi) Raffineria di Gela SpA and Eni Rewind SpA (former Syndial
SpA) - Groundwater pollution survey and reclamation
process of the Gela site. Following complaints made by former
contractors, the Public Prosecutor's Office of Gela issued
an inspection and seizure of the area called Isola 32 within
the refinery of Gela, where old and new monitored landfills
are located. The proceeding concerns criminal allegations
of environmental pollution, omitted clean-up, negligent
personal injury and illegal waste management, as part of
the execution of clean-up of soil and groundwater as well as
decommissioning activities in the area currently managed by
Eni Rewind SpA, also on behalf of the companies Raffineria di
Gela SpA, ISAF SpA (in liquidation) and Versalis SpA (efficiency
and efficacy of the barrier system). The Public Prosecutor
acquired documents and evidence at the Syndial office in Gela
and at the refinery of Gela, which, during the period January
1, 2017 – March 20, 2019, managed the facilities involved in
cleaning up the groundwater area (TAF Syndial, site TAF-TAS
and pumping wells and hydraulic barrier). Subsequently a
decree was issued for the seizure of eleven (11) piezometers
of the hydraulic barrier system with contextual guarantee
notice, issued by the Public Prosecutor of Gela against nine
employees of Gela Refinery and four employees of Syndial
SpA. The proceedings are ongoing.
(xvii) Eni Rewind SpA (former Syndial SpA) and Versalis –
Mantua. Environmental crime investigation. The Public
Prosecutor of Mantua has initiated a series of proceedings
against companies of the Eni group and employees of Eni
for alleged environmental crimes related to the Mantua
industrial hub. Investigations, whose terms have been
extended, are in progress. The Prosecutor of Mantua is
proceeding for the crime of omitted clean-up, both according
to the case foreseen by the Consolidated Environmental Text
and for the hypothesis foreseen by the penal code "up to the
present". Eni companies are being investigated pursuant to
Legislative Decree No. 231/01.
1.2. Civil and administrative proceedings in the matters of
environment, health and safety
(i) Eni Rewind SpA (former Syndial SpA) – Summon for
alleged environmental damage caused by DDT pollution
in the Lake Maggiore. In May 2003, the Ministry for the
Environment claimed compensation from Eni Rewind for
alleged environmental damage caused by the activity at the
Pieve Vergonte plant in the years 1990 through 1996. In July
2008, the District Court of Turin ordered Eni Rewind to pay
environmental damages amounting to €1,833.5 million, plus
interests accrued from the filing of the decision. Eni and its
subsidiary deemed the amount of the environmental damage
to be absolutely groundless as the sentence lacked sufficient
elements to support such a material amount of the liability
from the volume of pollutants ascertained by the Italian
Environmental Minister. In July 2009, Eni Rewind filed an
appeal and consequently the proceeding continued before
a second Instance Court of Turin that requested a technical
appraisal on the matter. The consultants that undertook
this appraisal concluded that: (i) no further measure for
environmental restoration is required; (ii) there was no
significant and measurable impact on the environment of the
ecosystem, therefore no restoration or damage compensation
should be claimed; the only impact seen concerned fishing
activity, with an estimated damage of €7 million which could
be already restored through the measures proposed by Eni
Rewind, and; (iii) the necessity and convenience of dredging
should be excluded, both from the legal and scientific point
of view, while confirming technical and scientific correctness
of the Eni Rewind’s approach based on the monitoring of the
process of natural recovery, which is estimated to require 20
years. In March 2017, the second Instance Court: (i) excluded
the application of compensation for monetary equivalent;
(ii) annulled the monetary compensation of €1.8 billion
requesting Eni Rewind to perform the already approved clean-
up project of the polluted areas, which comprise groundwater,
as well as compensatory remediation works. The value of
these compensatory works required by the Court, in case
of Eni Rewind failure or misperformance, is estimated at
€9.5 million. The clean-up project filed by Eni Rewind was
ratified by the authorities and is currently being executed.
Expenditures expected to be incurred have been provisioned
in the environmental provision. Any other claims filed by the
Italian Minister for the Environment were rejected by the court
(including compensation for non-material damage). In April
2018, the Ministry for the Environment filed an appeal to the
Third Instance Court. In accordance with the law, the Company
and its managers filed an appeal and a counter-appeal.
(ii) Eni Rewind SpA (former Syndial SpA) – Versalis SpA – Eni
SpA (R&M) – Augusta harbor. The Italian Ministry for the
Environment with various administrative acts required
companies that were operating plants in the petrochemical
site of Priolo to perform safety and environmental remediation
works in the Augusta harbor. Companies involved include Eni
subsidiaries Versalis, Syndial and Eni Refining & Marketing
Division. Pollution has been detected in this area primarily due
to a high mercury concentration that is allegedly attributed to
the industrial activity of the Priolo petrochemical site. The above-
mentioned companies contested these administrative actions,
objecting in particular to the nature of the remediation works
decided and the methods whereby information on the pollutants
concentration has been gathered. A number of administrative
proceedings started on this matter were subsequently
merged before the Regional Administrative Court. In October
2012, the Court ruled in favor of Eni’s subsidiaries against the
Ministry's requirements for the removal of the pollutants and
the construction of a physical barrier. In September 2017, the
Ministry notified all the companies involved of a formal notice
for the start of remediation and environmental restoration of
the Augusta harbor within 90 days. The act, contested by the
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019 218
co-owner companies in December 2017, constitutes a formal
notice for environmental damage. The Administrative Council of
the Sicilian Region ruled on the appeals pending against various
decisions of the Regional Administrative Court and essentially
confirmed the cancellation of all administrative provisions
subject to the dispute. The annulment of the provisions had,
inter alia, retroactive effect to the time of their adoption and
therefore excludes the risk of claims of any possible breach of
administrative provisions. In June 2019, the Italian Ministry
for the Environment set up a permanent technical committee
to review the matter of the clean-up and reclamation of the
Augusta harbor. A report of the committee affirmed the 2017
warning of the Ministry and reaffirmed the State agencies and
local administrations’ view as to the environmental liability to be
charged to the companies operating in the area. In coordination
with the other companies operating at the site, the report is
being appealed and further technical analyses have been
commenced for defensive purposes. Eni’s subsidiary proposed
to the Italian Environmental Ministry to start a collaboration
with other interested parties to find remediation measures
based on new available environmental data collected by
independent agencies.
(iii) Eni SpA – Eni Rewind SpA (former Syndial SpA) – Raffineria di
Gela SpA – Claim for preventive technical inquiry. In February
2012, Eni’s subsidiaries Raffineria di Gela SpA and Eni Rewind
SpA and the parent company Eni SpA (involved in this matter
through the operations of the Refining & Marketing Division)
were notified of a claim issued by the parents of children with
birth defects in the Municipality of Gela between 1992 and
2007. The claim called for an inquiry aimed at determining
any causality between the birth defects suffered by these
children and any environmental pollution caused by the Gela
site, quantifying the alleged damages suffered and eventually
identifying the terms and conditions to settle the claim. The
same issue was the subject of previous criminal proceedings,
of which one closed without determining any illegal behavior
on the part of Eni or its subsidiaries, while a further criminal
proceeding is still pending. In December 2015, the three
companies involved were sued in relation to a total of 30 cases
of compensation for damages in civil proceedings. In May 2018,
the Court issued a first instance judgment concerning one
case. The Judge rejected the claim for damages, acknowledging
the arguments of the defendant companies in relation to the
absence of evidence concerning the existence of a causal link
between the birth defects and the alleged industrial pollution.
The judgement has been appealed.
(iv) Environmental claim relating to the Municipality of Cengio.
Since 2008 a proceeding is pending by the Court of Genoa,
brought by The Ministry for the Environment and the Delegated
Commissioner for Environmental Emergency in the territory of
the Municipality of Cengio. Those parties summoned Eni Rewind
before a Civil Court and demanded Eni’s subsidiary compensate
for the environmental damage relating to the site of Cengio. The
request for environmental damage amounted to €250 million to
which was to be added health damage to be quantified during
the proceeding. The plaintiffs accused Eni Rewind of negligence
in performing the clean-up and remediation of the site. In March
2019, the Ministry for the Environment presented a proposal
to Syndial to settle the case. The Company responded with
a counter-proposal in July 2019. The judge is verifying the
progress and status of the negotiations.
(v) Eni Rewind SpA (former Syndial SpA) and Versalis SpA –
Summon for alleged environmental damage caused by illegal
waste disposal in the municipality of Melilli (Sicily). In May
2014, the Municipality of Melilli summoned Eni’s subsidiaries
Eni Rewind and Versalis for the environmental damage allegedly
caused by carrying out illegal waste disposal activities and
unauthorized landfill. In particular, the plaintiff alleged Eni
Rewind and Versalis were responsible because they produced
the waste and commissioned the waste disposal. The plaintiff
stated that this illegal handling of waste was part of certain
criminal proceedings dating back to 2001–2003 which would
have allegedly traced the hazardous waste materials back to the
Priolo and Gela industrial sites that are managed by the above-
mentioned Eni’s subsidiaries (in particular, the waste with high
mercury concentration and railway sleepers no longer in use).
Such waste was allegedly handled and disposed illegally at an
unauthorized landfill owned by a third party. Two subsidiaries of
Eni and a third-party waste company were claimed to be jointly
and severally liable for damage amounting to €500 million. The
third-party company executed waste disposal at the site. In
June 2017, the Judge accepted all the defensive instances of Eni
Rewind and Versalis, judging the requests of the Municipality
to be inadmissible for lacking right to sue, also considering
the requests to be unfounded or unproved, and ordered the
Municipality to refund the expenses of the proceeding. In April
2018, the First Instance Judge rejected the counterclaim filed
by the Municipality. An appeal by the Municipality before a Third
Instance Court is pending.
(vi) Val D’Agri - Eni / Vibac. In September 2019 a claim was brought
in the Court of Potenza against Eni. The plaintiffs are eighty
people, living in different municipalities of the Val d’Agri area,
who are complaining of economic, non-economic, biological
and moral damages, all deriving from the presence of Eni’s oil
facilities in the territory. In particular, the claim refers to certain
events which allegedly caused damage to the local community
and the territory (such as a 2017 spill, flaring events since
2014, smelly and noisy emissions). The Judge has been asked
to ascertain Eni's responsibility for causing emissions of
polluting substances into the atmosphere. The plaintiffs have
also requested Eni be ordered to interrupt any polluting activity
and to be allowed to resume industrial activities on condition
that all the necessary remediation measures be implemented
to eliminate all of the alleged dangerous situations. Finally, they
are asking that Eni compensate all direct and indirect property
damages, current and future, to an extent to be quantified
during the proceedings.
(vii) Eni SpA - Climate change. In 2017 and 2018, local government
authorities and a fishing association brought in the courts of
the State of California seven proceedings against Eni Group
companies and other oil companies. These proceedings claim
compensation for the damages attributable to the increase in
sea level and temperature, as well as to the hydrogeological
instability. The cases have been transferred, by request of
the defendants, from the State Courts to the Federal Courts.
A specific request has been filed, highlighting the lack of
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jurisdiction of the State Courts. The proceedings are currently
suspended and waiting for a jurisdictional competence.
2. Proceedings concerning criminal/administrative
corporate responsibility
(i) EniPower SpA. In 2004, the Public Prosecutor of Milan
commenced inquiries into contracts awarded by Eni’s
subsidiary EniPower SpA and as to supplies provided by other
companies to EniPower SpA. It emerged that illicit payments
were made by EniPower SpA suppliers to a manager of EniPower
SpA who was immediately fired. The Court served EniPower
SpA (the commissioning entity) and Snamprogetti SpA, now
Saipem SpA (contractor of engineering and procurement
services), with notices of investigation pursuant to Legislative
Decree No. 231/01. In August 2007, Eni was notified that the
Public Prosecutor requested the dismissal of EniPower SpA
and Snamprogetti SpA, while the proceeding continues against
former employees of these companies and employees and
managers of the suppliers pursuant to Legislative Decree No.
231/01. Eni SpA, EniPower SpA and Snamprogetti SpA presented
themselves as plaintiffs. In September 2011, the Court of
Milan found that nine persons were guilty for the above-
mentioned crimes. In addition, they were sentenced jointly
and severally to the payment of all damages to be assessed
through a specific proceeding and to the reimbursement
of the proceeding expenses incurred by the plaintiffs. The
Court also resolved to dismiss all the criminal indictments
for 7 employees, representing some companies involved as
a result of the statute of limitations, while the trial ended
with an acquittal of 15 defendants. In reference to the parts
involved in the proceeding pursuant to Legislative Decree No.
231/01, the Court found that 7 companies are responsible for
the administrative offenses ascribed to them, imposing a fine
and the disgorgement of profit. The Court rejected the position
as plaintiffs of the Eni Group companies, reversing the prior
decision made by the Court. This decision may have been made
based on a pronouncement made by a Third Instance Court that
stated the illegitimacy of the constitution as plaintiffs against
any legal entity, as indicted pursuant to Legislative Decree
No. 231/01. The sentenced parties filed appeal against the
above-mentioned decision. The Appeal Court issued a ruling that
substantially confirmed the first-degree judgment except for
the fact that it ascertained the statute of limitation with regard
to certain defendants. The Third Instance Court successively
annulled the judgment of the Second Instance Court ascribing
the judgment to another section that, once more, confirmed the
sentence of first instance, excepting the rulings of the previous
appeal sentence not subject to annulment, including the statute
of limitation. The grounds of the sentence have been filed
confirming the motivations provided by the previous instance
Courts. An appeal was filed at the Third Instance Court solely for
the purposes of the civil proceeding.
(ii) Algeria. Legal proceedings are pending in Italy and outside Italy
in connection with an allegation of corruption relating to the
award of certain contracts to Eni’s former subsidiary Saipem
in Algeria. In 2011, Eni received from the Public Prosecutor of
Milan an information request in accordance with the Italian
Code of Criminal Procedure. The request related to allegations
of international corruption and pertained to certain activities
performed by Saipem Group companies in Algeria (in particular
the contract between Saipem SpA and Sonatrach relating to the
construction of the GK3 gas pipeline and the contract between
Galsi, Saipem SpA and Technip relating to the engineering of
the ground section of a gas pipeline). The crime of international
corruption is among the offenses pursuant to Legislative Decree
No. 231/01, which provides for corporate liability for crimes
committed by employees and prescribes punishments including
fines and the disgorgement of profit. Eni also voluntarily
provided to the Public Prosecutor documentation relating to the
MLE project (in which Eni’s Exploration & Production Division
participates), with respect to which investigations in Algeria
are ongoing. In November 2012, the Public Prosecutor served
Saipem a notice stating that it had commenced an investigation
for alleged liability of the company for international corruption
pursuant to Legislative Decree No. 231/01. Furthermore,
the Public Prosecutor requested the production of certain
documents relating to certain activities in Algeria. Subsequently,
the Public Prosecutor’s Office notified further measures and
requests to Saipem, aimed at acquiring further documentation,
in particular relating to certain intermediary contracts and
sub-contracts entered into by Saipem in connection with its
Algerian business. Several former Saipem employees were also
involved in the proceeding, including the former CEO of Saipem
SpA, who resigned from the office in December of 2012, and the
former Chief Operating Officer of the Business Unit Engineering
& Construction of Saipem, the employment of whom was
terminated at the beginning of 2013. In February 2013, on
mandate from the Public Prosecutor of Milan, the Italian
Finance Police visited Eni’s headquarters in Rome and San
Donato Milanese and executed searches and seized documents
relating to Saipem’s activity in Algeria. On the same occasion,
Eni was served a notice that an investigation had commenced
pursuant to Legislative Decree No. 231/01 with respect to Eni,
Eni’s former CEO, Eni’s former CFO and another senior manager.
Eni’s former CFO had previously served as Saipem’s CFO,
including during the period in which alleged corruption took
place and before being appointed as CFO of Eni on August 1,
2008. Following receipt of this notice, Eni conducted an internal
investigation with the assistance of external consultants, in
addition to the review activities performed by its audit and
internal control departments and a team dedicated to the
Algerian matters. The external consultants reached the following
results: (i) the review of the documents seized by the Milan
prosecutors and the examination of internal records held by
Eni’s global procurement department did not find any evidence
that Eni entered into intermediary or any other contractual
arrangements with the third parties involved in the prosecutors’
investigation; the brokerage contracts that were identified, were
signed by Saipem or its subsidiaries or predecessor companies;
and (ii) the internal review made on the MLE project, the only
project that Eni understands to be under the prosecutors’
investigation where the client is an Eni Group company did not
find evidence that any Eni employee engaged in wrongdoing in
connection with the award to Saipem of two main contracts to
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execute the project (EPC and Drilling). Furthermore, in 2014,
with the assistance of external consultants, Eni completed a
review of the extent of its operating control over Saipem with
regard to both legal, accounting and administrative issues.
The findings of that review confirmed the autonomy of Saipem
from the parent company during the relevant periods. The
findings of Eni’s internal review have been provided to the
Judicial Authority in order to reaffirm Eni’s willingness to fully
cooperate. In January 2015, the Public Prosecutor notified
the conclusion of preliminary investigations relating to Eni,
Saipem and eight persons (including, the former CEO and CFO
of Eni SpA and the Chief Upstream Officer of Eni SpA who was
responsible for Eni Exploration & Production activities in North
Africa at the time of the events under investigation). The Public
Prosecutor issued a notice of alleged international corruption
against all such persons (including Eni SpA and Saipem SpA
pursuant to Legislative Decree No. 231/01) in connection with
the entry into intermediary contracts by Saipem in Algeria. In
February 2015, the Public Prosecutor requested the indictment
of all the investigated persons for international corruption as
well as for tax offenses. In 2015, the Judge for the Preliminary
Hearing of the Court of Milan dismissed the case and granted
an acquittal in favor of Eni SpA, former Chief Executive Officer
and Chief Upstream Officer for all the alleged offenses. In
February 2016, the Third Instance Court, upholding an appeal
presented by the Public Prosecutor, reversed the dismissal and
remanded the proceedings to another Judge for the Preliminary
Hearing in the Court of Milan. As a result of a new preliminary
hearing in July 2016, the Judge ordered the trial for all
defendants, including Eni SpA. At a hearing in February, 2018,
the Public Prosecutor, concluding his indictment, requested –
among other things – the imposition on Eni SpA of a pecuniary
sanction. In September 2018, the Court of Milan rejected in part
the charges of the Public Prosecutor and issued an acquittal
verdict for Eni, for the former CEO and for the Company’s Chief
Upstream Officer in relation to all charges. The former CFO of Eni
was also acquitted of charges relating to Eni's involvement. In
December 2018 the court filed a written opinion setting forth
the basis for its rulings. The Public Prosecutor and the parties
who were convicted in the first trial have appealed under
the terms of the law. On January 15, 2020, the second penal
section of the Court of Appeal of Milan confirmed the first-
degree acquittal sentence against the former Eni managers,
declaring the appeal proposed by the Public prosecutor
inadmissible against the Company.
In 2012, Eni contacted the US Department of Justice (DoJ) and
the US SEC in order to voluntarily inform them about this matter,
and has kept them informed about the developments in the
Italian Prosecutors’ investigations and proceedings. Following
Eni’s notification, both the US SEC and the DoJ started their own
investigations regarding this matter. Eni has furnished various
information and documents, including the findings of its internal
reviews, in response to formal and informal requests. In September
2019, the DoJ notified Eni that based on the information it
currently possessed, the DoJ was closing its investigation of Eni in
connection with Eni's and Saipem's businesses in Algeria without
the filing of any charges. Eni is currently in advanced discussions
with the SEC about a potential resolution of the SEC's investigation.
(iii) Block OPL 245 – Nigeria. A criminal case is pending before the
Court of Milan alleging international corruption in connection
with the acquisition in 2011 of the OPL 245 exploration block
in Nigeria. In July 2014, the Public Prosecutor of Milan served
Eni with a notice of investigation pursuant to Italian Legislative
Decree No. 231/01. The proceeding was commenced following
a claim filed by NGO ReCommon relating to alleged corruptive
practices which, according to the Public Prosecutor, allegedly
involved the Resolution Agreement made on April 29, 2011
relating to the so-called Oil Prospecting License of the offshore
oilfield that was discovered in OPL 245. Eni fully cooperated
with the Public Prosecutor and promptly filed the requested
documentation. Furthermore, Eni voluntarily reported the
matter to the US Department of Justice and the US SEC.
In July 2014, Eni’s Board of Statutory Auditors jointly with
the Eni Watch Structure resolved to engage an independent,
US-based law firm, expert in anticorruption, to conduct a
forensic, independent review of the matter, upon informing the
Judicial Authorities. After reviewing the matter, the US lawyers
concluded that they detected no evidence of wrongdoing by Eni
in relation to the 2011 transaction with the Nigerian government
for the acquisition of the OPL 245 license. In September 2014,
the Public Prosecutor notified Eni of a restraining order issued
by a British judge who ordered the seizure of a bank account
not pertaining to Eni domiciled at a British bank following a
request from the Public Prosecutor. Since the act had also
been notified to some persons, including the CEO of Eni and the
former Chief Development, Operation & Technology Officer of
Eni and the former CEO of Eni, it was assumed that the same
had been registered in the register of suspects at the Milan
Prosecutor's office. During a hearing before a court in London
in September 2014, Eni and its current executive officers stated
their non-involvement in the matter regarding the seized bank
account. Following the hearing, the Court reaffirmed the seizure.
In December 2016, the Public Prosecutor of Milan notified Eni of
the conclusion of the preliminary investigation and requested
Eni’s CEO, the Chief Development, Operations and Technological
Officer and the Executive Vice President for international
negotiations to stand trial, as well as Eni’s former CEO and Eni
SpA, pursuant to Italian Legislative Decree No. 231/01. Upon
the notification to Eni of the conclusion of the preliminary
investigation by the Public Prosecutor, the independent US-
based law firm was requested to assess whether the new
documentation made available from Italian prosecutors could
modify the conclusions of the prior review. The US law firm
was also provided with the documentation filed in the Nigerian
proceeding mentioned below. The independent US law firm
concluded that the reappraisal of the matter in light of the new
documentation available did not alter the outcome of the prior
review. In September 2019, the DoJ notified Eni that based on
the information it currently possessed, the DoJ was closing its
investigation of Eni in connection with OPL 245 without the filing
of any charges.
In December 2017, the Judge for preliminary investigation
ordered the indictment of all the parties mentioned above,
and other parties under investigation by the Public Prosecutor,
before the Court of Milan. The request of the Federal
Government of Nigeria (FGN) for admission as a civil claimant
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221
in the proceedings was granted in July 2018.The first instance
trial of the Milan Prosecutor's OPL 245 charges began before
the Court of Milan on June 20, 2018 and is currently ongoing.
In a separate criminal proceeding, two defendants, neither of
whom is a current or former employee of the Company, chose to
have their liability determined by the Judge for the Preliminary
Hearing on the basis of the evidence presented by the Milan
Prosecutor at the preliminary hearing. In September 2018, the
Judge convicted these defendants and sentenced them both
to four-year detention terms and the disgorgement of profits
amounting to approximately €100 million. In December 2018,
the Judge for the Preliminary Hearing filed a written opinion
setting forth the basis for these rulings. The defendants filed an
appeal against this sentence.
In January 2017, Eni’s subsidiary Nigerian Agip Exploration
Ltd (“NAE”) became aware of an Interim Order of Attachment
(“Order”) issued by the Nigerian Federal High Court upon
request from the Nigerian Economic and Financial Crimes
Commission (EFCC), attaching OPL 245 temporarily pending a
proceeding in Nigeria relating to alleged corruption and money
laundering. After making this application, Eni became aware
of a formal filing of charges by the EFCC against NAE and other
parties. In March 2017, the Nigerian Court revoked the Order.
To NAE’s knowledge EFCC charges have not been dropped but
none of the defendants were served nor arraigned. In November
2018, Eni SpA and its subsidiaries NAE, NAOC and AENR (as
well as some companies of the Shell Group) were notified of
the intention of the FGN to bring a civil claim before an English
court to obtain compensation for damages allegedly deriving
from the transaction that resulted in assignment of the OPL
245 to NAE and Shell subsidiary SNEPCO (Shell subsidiary).
On April 15, 2019 the Nigerian subsidiaries NAE, NAOC and
AENR received formal notification of the commencement of the
proceeding, while similar notification was received by Eni SpA
on May 16, 2019. In the introductory deeds of the proceeding,
the claim is set at $1.092 billion or at any other amount that
will be established during the proceedings. The FGN has based
its assessment on an estimated fair value of the asset of $3.5
billion. Eni’s interest in the asset is 50%. As the FGN is also
acting as claimant in the Italian proceeding before the Court of
Milan, this claim appears to duplicate the claims made before
the Milan’s Court against Eni employees.
(iv) Congo. In March 2017, the Italian Finance Police served Eni
with an information request in accordance with the Italian
Code of Criminal Procedure in connection with an investigative
file opened by the Public Prosecutor of Milan against unknown
persons. The request related in particular to the agreements
signed by Eni Congo SA with the Ministry of Hydrocarbons of
the Republic of Congo in 2013, 2014 and 2015 in relation to
exploration, development and production activities concerning
certain permits held by Eni Congo SA for Congolese projects
and Eni’s relationships with Congolese companies that hold
stakes in those projects. In July 2017, the Italian Financial
Police, on behalf of the Public Prosecutor of Milan, served Eni
with another information request and a notice of investigation
pursuant to Legislative Decree No. 231/01 for alleged
international corruption. The request expressly stated that
it was based in part on the March 2017 information request
and concerned the relationship of Eni and its subsidiaries
with certain third-party companies from 2012 to the present.
Eni produced all of the documentation requested in March
and July 2017 and voluntarily disclosed this matter to the
relevant US authorities (SEC and DoJ). In April 2018, the Public
Prosecutor of Milan served Eni SpA with a further request for
documentation and notified an Eni employee, who was the
then Chief Development, Operation & Technology Officer, of a
search order stating that he and another Eni employee had
been placed under investigation.
In December 2018 and subsequently in May and September
2019, Eni was notified by the Public Prosecutor of Milan for
documents in accordance with the Italian Code of Criminal
Procedure, concerning some economic transactions between
Eni Group companies and certain third-party companies. All the
required documentation has been produced to the Judge.
In April 2018, the Board of Statutory Auditors, the Watch
Structure and the Control and Risk Committee of Eni jointly
appointed an independent law firm and a professional
consulting company, knowledgeable in the matter of anti-
corruption, to carry out a forensic review of facts relating
to Eni's work in Congo. Such review did not find any factual
evidence as to the involvement of Eni, nor of any Eni
employees and key managers, in the alleged crimes. The
Report resulting from this review was brought to the attention
of the Public Prosecutor and the relevant US authorities
(SEC and DoJ).
In September 2019, the Company was informed that the Company’s
CEO was served with a search decree and an investigation decree in
connection with an alleged violation of article 2629 bis of the Italian
Civil Code which penalizes directors of listed companies that fail
to communicate conflicts of interest. The alleged omission relates
to the supply of logistics and transportation services to certain
Eni’s subsidiaries operating in Africa, among which Eni Congo SA,
by third-party companies owned by Petroserve Holding BV, in
the period 2007-2018. The accusation is based on the allegations
that the wife of the Company’s CEO retained a shareholding of the
above-mentioned holding company over part of the period of time
under investigation. The Board of Directors of Eni SpA has never
been involved in any resolution concerning the suppliers under
investigation.
In November 2019, following the notification of further
investigative documents, the Board of Statutory Auditors,
the Control and Risk Committee and the Watch Structure of
Eni asked the consultants, which had been engaged in 2018,
also to review the conclusions reached, in the light of the
documentation made available following the decree notified
to the CEO in September 2019. The second report of the
consultants, which was delivered in February 2020, still of a
preliminary nature and subject to modifications and follow-
up, updates the conclusions reached by the first report and
indicated that: (i) it is probable that the CEO's wife held a
shareholding in the Petroserve Group for a few years starting
from 2009 until 2012 and in any case no later than the date the
CEO was appointed Board member; (ii) there is an absence of
evidence to contradict the statements made by the CEO as to
his lack of knowledge of his wife's interests in the ownership of
Petroserve Group.
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3. Other proceedings concerning criminal matters
(i) Eni SpA (R&M) – Criminal proceedings on fuel excise tax. A
criminal proceeding is currently pending, relating to alleged
evasion of excise taxes in the context of retail sales in the fuel
market. In particular, the claim states that the quantity of oil
products marketed by Eni was larger than the quantity subjected
to the excise tax. This proceeding (No. 7320/2014 RGNR) concerns
the combination of three distinct investigations: (i) a first
proceeding, opened by the Public Prosecutor’s Office of Frosinone
involved a company (Turrizziani Petroli) purchaser of Eni’s fuel.
This investigation was subsequently extended to Eni. The Company
fully cooperated and provided all data and information concerning
the excise tax obligations for the quantities of fuel coming from
the storage sites of Gaeta, Naples and Livorno. Such proceeding
referred to quantities of oil products sold by Eni, allegedly larger
than the quantity subjected to the excise tax. On June 24, 2019, a
settlement agreement was signed between Eni and the Customs
Agency, involving the determination of the excise tax of €73
thousand and the reimbursement to Eni of the exceeding amounts
paid while the judgment was pending. Consequently, an application
to cease the dispute was presented to the Tax Commission. (ii)
a second proceeding, concerning an investigation by the Public
Prosecutor’s Office of Prato, commenced in regard to the deposit
of Calenzano and relates to abduction of fuel through manipulation
of the fuel dispensers, subsequently extended also to the Refinery
of Stagno (Livorno); (iii) a third proceeding, opened by the Public
Prosecutor’s Office of Rome, concerns alleged missing payment
of excise tax on the surplus of the unloading products, as the
quantity of such products was larger than the quantity reported
in the supporting fiscal documents. This proceeding represents
a development of the first proceeding mentioned above and
substantially concerns similar facts presenting, however, some
differences with regard to the nature of the alleged crimes and the
responsibility.
The Public Prosecutor’s Office of Rome has alleged the existence
of a criminal conspiracy aimed at habitual abduction of oil
products at all of the 22 storage sites which are operated by Eni
in Italy. Eni is cooperating with the Prosecutor in order to defend
the correctness of its operation. In September 2014, a search was
conducted at the office of the former chief of the R&M Division in
Rome. The motivations of the search are the same as the above-
mentioned proceeding as the ongoing investigations also relate
to a period of time when the officer was in charge at Eni’s R&M
Division. In March 2015, the Prosecutor of Rome ordered a search
at all the storage sites of Eni’s network in Italy as part of the same
proceeding. The search was intended to verify the existence of
fraudulent practices aimed at tampering with measuring systems
functional to the tax compliance of excise duties in relation to
fuel handling at the storage sites. In September 2015, the Public
Prosecutor of Rome requested a one-off technical appraisal aimed
to verify the compliance of the software installed at certain metric
heads previously seized with those lodged by the manufacturer
at the Ministry of Economic Development. The technical appraisal
verified the compliance of the software tested. The proceeding
was then extended to a large number of employees and former
employees of the Company. Eni has continued to provide full
cooperation to the authorities.
During the course of 2018, as part of the general proceeding no.
7320/2014, the Public Prosecutor of Rome notified the conclusion of
the preliminary investigations in relation to the criminal proceeding
concerning the Calenzano, Pomezia, Naples, Gaeta and Ortona
storage sites and the Livorno and Sannazzaro refineries. Based on
the outcome of the investigations, as far as Eni is concerned, the
proceeding involves former managers and directors of the logistic
sites and refineries indicated above concerning alleged aggravated
and continuous non-payment of excise duties, alteration and
removal of seals, use and possession of false measures and
weights instruments. In addition for the Calenzano site, three
employees and their manager of the storage site were accused of
alleged procedural fraud.
In September 2018, Eni received, as injured party, the notification
of the schedule of hearing issued by the Court of Rome, in relation
to criminal association and other minor claims, against numerous
persons under investigation – including over forty Eni employees
– subject of a separated proceeding (No. 22066/17 RGNR), for
which, in May 2017, the Public Prosecutor’s Office had requested
the dismissal. At the end of the hearing in December 2018, the
Judge accepted the request for dismissal for several persons
under investigation, including thirteen Eni employees. The Judge
also initially rejected the request of indictment for criminal
association relating twenty-eight Eni employees (including the
former managers of the R&M Division).
As part of the separate proceeding No. 22066/2017 RGNR,
following the re-filing by the Public Prosecutor of the indictment
for criminal association, following a preliminary hearing, the
judge resolved to dismiss the case against all of the defendants
because allegations were found to be groundless.
In April 2018 as part of the administrative proceeding intended
to collect taxes allegedly unpaid by Eni, the tax police of Rome
based on the findings of the investigations performed by the
prosecutors of Frosinone, Prato and Rome issued a statement of
objection against the Company claiming the missed payment of
excise taxes due for the years 2008 up to 2017 for €34 million,
as well as the related higher corporate profits before income
taxes leading to the claim of additional taxes for €22 million
related to income taxes and VAT. The Custom Agency that is in
charge of issuing the notice of payment may also impose a fine
and the recognition of interest expense. A part of the disputed
amounts for excise taxes and other related taxes concerned
the same litigation, which was successfully challenged by the
Company following a recourse filed with the Tax Commission
of Rome and in relation to which the Company agreed upon an
extrajudicial transaction with the Tax Authorities.
Following the documentation presented by the Company, the
Customs Agency determined the excise tax due in the amount
of €8 million by issuing the payment notices in July 2019.
Furthermore, the Agency estimated €6 million of other related
taxes. The Company has paid the amounts determined by the
Agency.
(ii) Eni SpA – Public Prosecutor of Milan – Criminal proceeding
No. 12333/2017. In February 2018, Eni was notified of a search
and seizure decree in relation to allegations of associative
crime aimed at slander and at reporting false information to
a Public Prosecutor. In the decree, the Prosecutor of Milan
included, among the other persons under investigation, a former
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223
external lawyer and a former Eni manager, at the time of the
facts holding strategic positions in the Company. According to
the decree, the association is allegedly aimed at interfering
with the judicial activity in certain criminal proceedings that
are involving, among others, Eni and some of its directors and
managers. Afterwards, the Control and Risks Committee, having
consulted the Board of Statutory Auditors, and together with the
Watch Structure, agreed to engage an auditing firm to perform
an internal audit of all relevant facts and circumstances and all
records and documentation relating to the matter with respect
to the events of the aforementioned proceeding, including a
forensic review. The final report, submitted to the Control and
Risk Committee, the Watch Structure and the Board of Statutory
Auditors on September 12, 2018, concluded that following the
review carried out with respect to the allegations made by the
Public Prosecutor of Milan, there was not sufficient factual
evidence to prove the involvement of the aforementioned
former manager of Eni in the alleged crimes. On April 19, 2018,
the Board of Directors appointed two external consultants,
a criminal lawyer and a civil lawyer to provide independent
legal advice in relation to the facts under investigation. Their
report, dated November 22, 2018, did not find facts which could
suggest any involvement of any Eni employees in the crimes
alleged by the Public Prosecutor. On June 4, 2018, Consob, the
Italian market regulator, requested to be informed about the
above mentioned proceeding. The request was addressed to the
Company and to its Board of Statutory Auditors.
Specifically, Consob asked for the outcome of the forensic
review and to be updated about any other audit action taken
in relation to the matter by the Company and by its board
of Statutory Auditors. The Board of Statutory Auditors was
also requested to report about the findings of the additional
audit program agreed with an external auditor regarding
the matter and to keep Consob updated about any further
initiatives adopted. The Company answered the request
on June 11, 2018. Subsequently, the Company finalized its
response by sending further documentation including the final
report of the independent third party and the reports of the
consultants of the Board of Directors. The Board of Statutory
Auditors has periodically updated Consob of the initiatives
taken as part of the Board’s monitoring responsibilities with
several communications. On June 13, 2018, Eni was notified
of a request from the Prosecutor Office to transmit certain
documentation in accordance with the Italian Code of Criminal
Procedure. The request targeted evidence and documents
relating to the internal audit performed by the Company and any
possible external review concerning certain tasks that had been
assigned to the former external lawyer with respect to Eni. This
lawyer appears to be investigated as part of this proceeding. The
reports of the independent third party and of the consultant of
the Board of directors were also sent to the Public Prosecutor.
In May and June 2019, in the context of the same proceeding,
the Court of Milan notified Eni and three of its subsidiaries
(ETS SpA, Versalis SpA, Ecofuel SpA) of various requests for
documentation in accordance with the Italian Code of Criminal
Procedure. At the same time, on May 23, 2019, Eni was served
a notice that the Company is being investigated pursuant to
Legislative Decree No. 231/01, with reference to the crime
sanctioned by the Italian Penal Code concerning “inducement
not to make statements or to make false statements to the
judicial authority”.
The object of the aforementioned requests particularly concerns
the relations with two business partners, access to Eni offices
of certain third parties, also on behalf of one of the above-
mentioned business partners, the mailbox of some employees
and former employees, the documentation concerning the
relations (and the interruption of those relations) with the
former external lawyer investigated in the proceeding, the
internal audit reports and the reports of the Company’s bodies
that dealt with assessing these relationships. Following internal
audits, on June 21, 2019, the Company sued for fraud a former
employee at its subsidiary ETS, who was fired on May 28,
2019, and also filed a complaint before the Judicial Authority to
ascertain possible complicity in fraud of other third parties.
On August 14, 2019, the Italian tax police sent a new request for
information to Eni, concerning the economic relations between
Eni Group companies and an external professional.
In November 2019, Eni received a notice to extend the preliminary
investigations. The notice also covered the investigations of the
alleged breach of certain provisions of Italian Law Decree 231/01
on part of Eni. Furthermore, it was ascertained that certain
former Eni employees have been charged with various criminal
allegations. Those employees were a former manager of Eni’s
legal department, the former Chief Upstream Officer of Eni and an
employee that was fired in 2013. A number of third parties have
also been indicted, among them, two former legal consultants
of Eni. On January 23, 2020, a search decree and an indictment
were notified to the Company’s Chief Services & Stakeholder
Relations Officer, the Senior Vice President for Security and to a
manager of the legal department. Moreover, further procedural
documentation became available following requests to review
the aforementioned decree. The Board of Statutory Auditors,
the Control Committee and the Watch Structure have instructed
the same consultants appointed in 2018 to examine the
aforementioned documentation, in order to review and summarize
the facts underlying those allegations, as well as other factual
elements and conduct to be examined in depth relating to the
existence of any substantial issue or possible deficiency in
the internal control and risk management system and in the
organization and risk management model pursuant to Legislative
Decree No. 231/01. The consultant's activities are ongoing.
(iii) Eni SpA – Public Prosecutor of Milan – Insider trading. In March
2019, a request for extending certain investigations was notified
to Eni’s Chief Upstream Officer by the public prosecutor office of
Milan. The commencement of those investigation was otherwise
not notified. The investigations related to an alleged breach of
Italian provisions that regulate insider trading and access to
market-sensitive information. The breach was allegedly made from
November 1 to December 1, 2016. There were no more informative
details about the alleged breach in the notified document.
4. Tax proceedings
(i) Dispute for omitted payment of a property tax for some
oil offshore platforms located in territorial waters. A Third
Instance Court in Italy with a ruling issued in 2016 established
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019
224
that Oil & Gas offshore platforms located within territorial
boundaries were subject to a property tax, resolving a dispute
that has been in progress for about a decade in favor of local
authorities. Eni was a party to many of these disputes and
has entered into settlement transactions with various local
authorities. Currently, a risk provision €17 million has been set
aside in the consolidated financial statements for the remaining
pending litigations.
The Third Instance Court ruling applied to the legislation in force
until 2015. Since 2016 the regulatory framework has changed
due to enactment of law No. 208/2015, which excluded from
the scope of the property tax the value of plants instrumental
to specific production processes. To clarify the effects of this
scope limitation of the property tax relating to above-mentioned
offshore platforms, in 2016 the Italian association of Oil &
Gas producers submitted a question to the Italian Finance
Department. The Department recognized that offshore platforms
met the requirements for classification as instrumental plants
and consequently are excluded from the scope of the property tax
(resolution No. 3/DF of June 1, 2016).
The ruling of the Department of Finance, however, is not binding
for local authorities with taxing powers and three of these have
issued assessment notices for 2016 and subsequent years. The
Company has challenged these notices in legal proceedings. To date
two first instance judgments have been issued, one in favor of the
Company and one against. A second instance judgement has also
been issued with results unfavorable to the Company. Of the two
unfavorable outcomes, only one applies penalties. One of the two
unfavorable judgements concerns the dispute with the municipality
of Ravenna for the years 2016 and 2017, that judgement confirmed
the assessment made by the municipality for a total tax of €19
million, in addition to the penalties applicable by law.
Based on the resolution of the Department of Finance in
2016, Eni believes that the scope limitation of the tax property
enacted in 2016 applies to offshore platforms located within
territorial boundaries and based on this the Company intends
to continue to contest the assessment. No risk provisions have
been accrued in the consolidated financial statements.
Law Decree 124/2019 (enacted with Law 157/2019) has
established, starting from 2020, that marine platforms are
subject to a new property tax that will replace and supersede any
other ordinary local property tax eventually levied on these plants
up to 2019. This rule has therefore sanctioned, starting from
2020, the existence of the tax requirement for these plants.
5. Settled Proceedings
(i) Reorganization procedure of Alitalia Linee Aeree Italiane SpA
under extraordinary administration. In January 2013, the
Italian airline company Alitalia summoned Eni, Exxon Italia
and Kuwait Petroleum Italia SpA before the Court of Rome, to
seek a compensation for alleged damages caused by alleged
anti-competitive behavior on part of the three petroleum
companies in the supply of jet fuel in the years 1998 through
2009. The claim was based on a decision rendered by the
Italian Antitrust Authority in June 2006. The antitrust decision
accused Eni and another five petroleum companies of anti-
competitive agreements designed to split the market for
jet fuel supplies and blocking the entrance of new players
in the years 1998 through 2006. In June 2019 the lawsuit
was settled between all the involved parties. The amount
transacted by Eni was previously accrued in the financial
statements.
(ii) Eni SpA - Public Prosecutor's Office of Rome - Criminal
Procedure No. 2711/2019 - VAT returns. On September 16,
2019, a notice of extension of the preliminary investigations
was notified to the former CEO and the current CEO of Eni,
in relation to the tax crime referred to in art. 4 of Legislative
Decree 74/2000 (unfaithful tax statement). From the first
investigations carried out by the defense attorney, the
allegations referred to the criminal proceedings on fuel excise
taxes, disclosed in the previous section and derived from
the alleged taxes due on the higher profit before taxation
ascertained as a result of evading the owed amounts of excise
taxes for fiscal years from 2011 to 2014. As a result of the
defensive activities carried out and due to the transaction
carried out with the Customs and Revenue Agency, in
November 2019 the Prosecutor filed a request to dismiss
the proceedings and on December 2, 2019 the Court of Rome
issued an order of dismissal.
(iii) Eni’s arbitration with GasTerra. In 2013, Eni initiated an
arbitration against GasTerra, as part of a long-term supply
contract signed in 1986, to obtain a revision of the price
charged by GasTerra to Eni for the gas supplied in the 2012–
2015 period. On that occasion, Eni and GasTerra agreed to
apply a provisional price, which was lower than the previous
price, until the definition of a new contractual price based on
an arrangement between parties or an arbitration award. The
arbitration award dismissed Eni’s claim for price revision,
without however determining a new price applicable in the
relevant period. GasTerra considered that, by dismissing Eni’s
claim, the award restored the original contract price, based on
which GasTerra claimed an additional amount to be paid by Eni
which corresponded to the difference between the provisional
price and the contractual price. Eni, relying also on the opinion
of its external consultants, did not agree with GasTerra’s
interpretation and considered GasTerra’s claim groundless.
However, GasTerra, based on its own interpretation, commenced
an arbitration and obtained from a Dutch court the provisional
seizure of Eni’s investment in its subsidiary Eni International
BV for the alleged receivable due by Eni (equal to €1.01
billion). With respect to the interim seizure measure obtained
by GasTerra, Eni offered to GasTerra, who in turn accepted, a
bank guarantee of the same amount of the GasTerra claim.
On July 8, 2019, the Tribunal issued an award concluding the
first phase of the procedure by which it decided, in particular,
that the provisional price mentioned above continued to apply
in the 2012-2015 period, and that therefore GasTerra was not
entitled to any price adjustment, so the invoices issued after
the rendering of the award in 2016 were invalid. The Tribunal
referred to the second phase of the arbitral procedure the
quantification of Eni’s claims for damages against GasTerra. On
July 24, 2019, upon Eni’s request and GasTerra consent, the
bank guarantee for €1.01 billion was terminated. GasTerra has
reserved its rights of appeal.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
225
Assets under concession arrangements
Eni operates under concession arrangements mainly in the
Exploration & Production segment and the Refining & Marketing
business line. In the Exploration & Production segment, contractual
clauses governing mineral concessions, licenses and exploration
permits regulate the access of Eni to hydrocarbon reserves.
Such clauses can differ in each Country. In particular, mineral
concessions, licenses and permits are granted by the legal
owners and, generally, entered into with government entities,
State oil companies and, in some legal contexts, private owners.
Pursuant to the assignment of mineral concessions, Eni sustains
all the operational risks and costs related to the exploration and
development activities and it is entitled to the productions realized.
As a compensation for mineral concessions, Eni pays royalties and
taxes in accordance with local tax legislation. In production sharing
agreement and service contracts, realized productions are defined
based on contractual agreements with State oil companies, which
hold the concessions. Such contractual agreements regulate the
recovery of costs incurred for the exploration, development and
operating activities (Cost Oil) and give entitlement to the own
portion of the realized productions (Profit Oil). In the Refining &
Marketing business line, several service stations and other auxiliary
assets of the distribution service are located in the motorway
areas and they are granted by the motorway concession operators
following a public tender for the sub-concession of the supplying
of oil products distribution service and other auxiliary services.
In exchange of the granting of the services described above, Eni
provides to the motorway companies fixed and variable royalties
based on quantities sold. At the end of the concession period, all non-
removable assets are transferred to the grantor of the concession
for no consideration.
Environmental regulations
Risks associated with the footprint of Eni’s activities on the
environment, health and safety are described in the “Financial
Review”, paragraph “Risk factors and uncertainties”. In the future,
Eni will sustain significant expenses in relation to compliance
with environmental, health and safety laws and regulations and
for reclaiming, safety and remediation works of areas previously
used for industrial production and dismantled sites. In particular,
regarding the environmental risk, management does not currently
expect any material adverse effect upon Eni’s Consolidated Financial
Statements, taking account of ongoing remediation actions, existing
insurance policies and the environmental risk provision accrued
in the Consolidated Financial Statements. However, management
believes that it is possible that Eni may incur material losses and
liabilities in future years in connection with environmental matters
due to: (i) the possibility of as yet unknown contamination; (ii) the
results of ongoing surveys and other possible effects of statements
required by Legislative Decree 152/2006; (iii) new developments in
environmental regulation (i.e. Law No. 68/2015 on crimes against
the environment and European Directive 2015/2193 on medium
combustion plants); (iv) the effect of possible technological changes
relating to future remediation; and (v) the possibility of litigation and
the difficulty of determining Eni’s liability, if any, as against other
potentially responsible parties with respect to such litigation and the
possible insurance recoveries.
Emission trading
From 2013, the third phase of the European Union Emissions
Trading Scheme (EU-ETS) came in force. The new phase marked a
significant change in the method of awarding emission allowance
from a no-consideration scheme based on historical emissions
to allocation through auctioning. For the period 2013–2020,
the award of free emission allowances is performed based on
European benchmarks specific to each industrial segment, except
for the thermoelectric sector that is not eligible for allocations for
no consideration. This regulatory scheme implies for Eni’s plants
subjected to emission trading a lower assignment of emission
permits respect to the emissions recorded in the relevant year and,
consequently, the necessity of covering the amounts in excess by
purchasing the relevant emission allowances on the open market.
In 2019, the emissions of carbon dioxide from Eni’s plants were
higher than the free allowances assigned to Eni. Against emissions
of carbon dioxide amounting to approximately 19.30 million
tonnes, Eni was awarded free emission allowances of 7.73 million
tonnes, determining a deficit of 11.57 million tonnes. This deficit
was entirely covered through the purchase of emission allowances
in the open market.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019 226
28 | Revenues and other income
SALES FROM OPERATIONS
(€ million)
2019
Sales from operations
Products sales and service revenues
Sales of crude oil
Sales of oil products
Sales of natural gas and LNG
Sales of petrochemical products
Sales of other products
Services
Transfer of goods/services
Goods/Services transferred in a specific moment
Goods/Services transferred over a period of time
2018
Sales from operations
Products sales and service revenues
Sales of crude oil
Sales of oil products
Sales of natural gas and LNG
Sales of petrochemical products
Sales of other products
Services
Transfer of goods/services
Goods/Services transferred in a specific moment
Goods/Services transferred over a period of time
2017
Sales from operations
Products sales and service revenues
Sales of crude oil
Sales of oil products
Sales of natural gas and LNG
Sales of petrochemical products
Sales of other products
Services
Exploration
& Production
Gas
& Power
Refining
& Marketing
and Chemicals
Corporate
and Other
activities
Total
10,499
38,160
21,017
205
69,881
3,505
1,189
5,454
68
283
10,499
9,946
553
17,334
3,000
12,468
316
2,502
2,540
38,160
38,047
113
27
16,615
3,772
16
587
21,017
20,768
249
9,943
43,109
22,594
3,982
1,133
4,554
27
247
9,943
9,676
267
18,471
4,053
15,088
762
2,363
2,372
43,109
42,979
130
17,213
4,777
20
584
22,594
22,535
59
7,131
39,846
19,771
2,431
1,030
3,470
14
186
7,131
17,693
3,930
11,643
147
2,021
4,412
39,846
17
14,615
4,591
21
527
19,771
20,866
20,804
17,922
4,110
2,593
3,586
69,881
68,848
1,033
75,822
22,453
22,399
19,642
5,574
2,421
3,333
75,822
75,296
526
66,919
20,141
19,575
15,113
4,770
2,068
5,252
66,919
22
7
176
205
87
118
176
35
11
130
176
106
70
171
32
12
127
171
(€ million)
Revenues associated with contract liabilities at the beginning of the period
Revenues associated with performance obligations totally or partially satisfied in previous years
2019
747
10
2018
342
11
Sales from operations by industry segment and geographical area
of destination are disclosed in note 35 – Segment information and
information by geographic area.
Sales from operations with related parties are disclosed in note 36
– Transactions with related parties.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
OTHER INCOME AND REVENUES
(€ million)
Gains from sale of assets and businesses
Other proceeds
227
2019
152
1,008
1,160
2018
454
662
1,116
2017
3,288
770
4,058
In 2019, gains from the sale of assets and businesses related for
€146 million to assets of the Exploration & Production segment.
In 2018, gains from the sale of assets and businesses related to the
divestment of a 10% stake in the Zohr project for €428 million. In
2017, the amount related to the divestment of a 25% stake in natural
gas-rich Area 4 offshore Mozambique (€1,985 million) and of a 40%
stake in the Zohr project (€1,281 million).
Other proceeds include €368 million related to the recovery
of the cost share of right-of-use assets pertaining to partners
of non-incorporated joint operations operated by Eni.
Other income and revenues with related parties are disclosed in note
36 – Transactions with related parties.
29 | Costs
PURCHASE, SERVICES AND OTHER CHARGES
(€ million)
Production costs - raw, ancillary and consumable materials and goods
Production costs - services
Lease expense and other
Net provisions for contingencies
Charges for price variation on overliftling and underlifting operations
Other expenses
less:
- capitalized direct costs associated with self-constructed assets - tangible assets
- capitalized direct costs associated with self-constructed assets - intangible assets
2019
36,272
11,589
1,478
858
879
51,076
(197)
(5)
50,874
2018
41,125
10,625
1,820
1,120
1,130
55,820
(192)
(6)
55,622
2017
35,907
12,228
1,684
886
145
931
51,781
(224)
(9)
51,548
Purchase, services and other charges include of geological and
geophysical costs of exploration activities for €275 million (€287 million
and €273 million in 2018 and 2017, respectively). In 2018 and 2017,
the item included operating leases for €872 million and €1,022 million,
respectively.
Costs incurred in connection with research and development activities
expensed through profit and loss, as they did not meet the requirements
to be recognized as long-lived assets, amounted to €194 million (€197
million and €185 million in 2018 and 2017, respectively).
Royalties on the extraction of hydrocarbons amounted to €1,183 million
(€1,043 million and €674 million in 2018 and 2017, respectively).
Additions to provisions net of reversal of unused provisions mainly related
to net addition for litigations amounting to €60 million (net provisions
of €101 million and €375 million in 2018 and 2017, respectively) and
net additions for environmental liabilities amounting to €329 million
(net provisions of €266 million and €200 million in 2018 and 2017,
respectively). More information is provided in note 20 – Provisions. Net
additions to provisions by segment are disclosed in note 35 – Segment
information and information by geographic area. Information about leases
is disclosed in note 12 – Right-of-use assets and lease liabilities.
PAYROLL AND RELATED COSTS
(€ million)
Wages and salaries
Social security contributions
Cost related to employee benefit plans
Other costs
less:
- capitalized direct costs associated with self-constructed assets - tangible assets
- capitalized direct costs associated with self-constructed assets - intangible assets
2019
2,417
449
85
213
3,164
(152)
(16)
2,996
2018
2,409
448
220
170
3,247
(142)
(12)
3,093
2017
2,447
441
113
162
3,163
(202)
(10)
2,951
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019
228
Other costs comprised provisions for redundancy incentives of €45
million (€37 million and €18 million in 2018 and 2017, respectively)
and costs for defined contribution plans of €99 million (€95 million
and €90 million in 2018 and 2017, respectively).
Cost related to employee benefit plans are described in note 21 –
Provisions for employee benefits.
Costs with related parties are disclosed in note 36 – Transactions with
related parties.
Average number of employees
The Group average number and breakdown of employees by category is reported below:
(number)
Senior managers
Junior managers
Employees
Workers
2019
2018
2017
Subsidiaries
1,014
9,267
15,945
4,910
31,136
Joint
operations
16
77
361
287
741
Subsidiaries
999
9,095
16,220
5,259
31,573
Joint
operations
17
84
361
283
745
Subsidiaries
995
9,089
16,721
5,659
32,464
Joint
operations
17
98
371
285
771
The average number of employees was calculated as the average
between the number of employees at the beginning and the end
of the period. The average number of senior managers included
managers employed in foreign Countries, whose position is
comparable to a senior manager’s status.
Long-term monetary incentive plan for the managers of Eni
On April 13, 2017, the Shareholders Meeting approved the Long-Term
Monetary Incentive Plan 2017-2019 and empowered the Board of
Directors to execute the Plan by authorizing it to dispose up to a
maximum of 11 million of treasury shares in service of the Plan.
The Long-Term Monetary Incentive Plan 2017-2019 provides for
three annual awards for the years 2017, 2018 and 2019 and is
intended for the Chief Executive Officer of Eni and for the managers
of Eni and its subsidiaries who qualify as “senior managers deemed
critical for the business”, selected among those who are in charge
of tasks directly linked to the Group results or of strategic clout to
the business. The Plan provides the granting of Eni shares for no
consideration to eligible managers after a three-year vesting period
under the condition that they would remain in office until vesting.
Considering that this incentive falls within the category of employee
compensation, in accordance with IFRS, the cost of the plan is
determined based on the fair value of the financial instruments
awarded to the beneficiaries and the number of shares that will be
granted at the end of the vesting period; the cost is accruing along
the vesting period.
The number of shares that will be granted at the end of the vesting
period is conditioned on a 50-50 basis to actual results of two
performance parameters against preset targets: (i) a market
condition in terms of Total Shareholder Return (TSR) of the Eni
share compared to the TSR of the FTSE Mib index of the Italian
Stock Exchange Market, and to a group of Eni's competitors ("Peers
Group”38) and the TSR of their corresponding stock exchange
market39; (ii) growth in the Net Present Value (NPV) of proved
reserves benchmarked against the Peer Group. Depending on the
performance of the parameters mentioned above, the number of
shares that will vest after three years may range between 0% and
180% of the initial award. Furthermore, 50% of the shares that will
eventually vest is subject to a lock-up clause of one year after the
vesting date.
The number of shares awarded at the grant date was 1,759,273 in
2019, 1,517,975 in 2018 and 1,719,061 in 2017; the weighted average
fair value of the shares at the same date was €9.88 per share in
2019, €11.73 per share in 2018 and €7.99 per share in 2017.
The estimation of the fair value was calculated by adopting
specific valuation techniques regarding the different performance
parameters provided by the plan (the stochastic method for the
market condition of the plan and the Black-Scholes model for the
component related to the NPV of the reserves), taking into account
the fair value of the Eni share at the grant date (€13.714 per share
in 2019; €14.246 per share in 2018; €13.81 per share in 2017),
reduced by dividends expected along the vesting period (6.1% of the
share price at vesting date in 2019; 5.8% of the share price at vesting
date in 2018; 5.8% of the share price at vesting date in 2017), the
volatility of the stock (19% for attribution 2019; 20% for attribution
2018; 25% for attribution 2017), the forecasts for the performance
parameters, as well as the lower value attributable to the shares
considering the lock-up period at the end of the vesting period.
In 2019, the costs related to the long-term monetary incentive plan
2017-2019, recognized as a component of the payroll cost, amounted
to €9 million (€5 million in 2018; €0.4 million in 2017) with a contra-
entry to equity reserves.
(38) The group consists of the following oil companies: Anadarko, Apache, BP, Chevron, ConocoPhillips, ExxonMobil, Marathon Oil, Royal Dutch Shell, Statoil and Total.
(39) The performance condition connected with the TSR in accordance with the international accounting standards represents a so-called market condition.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 229
Compensation of key management personnel
Compensation, including contributions and collateral expenses,
of personnel holding key positions in planning, directing and
controlling the Eni Group subsidiaries, including executive and non-
(€ million)
Wages and salaries
Post-employment benefits
Other long-term benefits
Indemnities upon termination of employment
Compensation of Directors and Statutory Auditors
executive officers, general managers and managers with strategic
responsibilities in office during the year consisted of the following:
2019
28
2
12
12
54
2018
27
2
10
39
2017
25
2
9
7
43
Compensation of Directors amounted to €9.2 million, €9.6 million and
€14.5 million for 2019, 2018 and 2017, respectively. Compensation
of Statutory Auditors amounted to €0.613 million, €0.604 million and
€0.760 million in 2019, 2018 and 2017, respectively.
Compensation included emoluments and social security benefits due for
the office as Director or Statutory Auditor held at the parent company Eni
SpA or other Group subsidiaries, which was recognized as a cost to the
Group, even if not subject to personal income tax.
30 | Finance income (expense)
(€ million)
Finance income (expense)
Finance income
Finance expense
Net finance income (expense) from financial assets held for trading
Income (expense) from derivative financial instruments
The analysis of finance income (expense) was as follows:
(€ million)
Finance income (expense) related to net borrowings
Interest and other finance expense on ordinary bonds
Net finance income (expense) on financial assets held for trading
Interest and other expense due to banks and other financial institutions
Interest on lease liabilities
Interest from banks
Interest and other income on financial receivables and securities held for non-operating purposes
Exchange differences
Income (expense) from derivative financial instruments
Other finance income (expense)
Interest and other income on financing receivables and securities held for operating purposes
Capitalized finance expense
Finance expense due to the passage of time (accretion discount)(a)
Other finance income (expense)
(a) The item related to the increase in provisions for contingencies that are shown at present value in non-current liabilities.
2019
2018
2017
3,087
(4,079)
127
(14)
(879)
3,967
(4,663)
32
(307)
(971)
3,924
(5,886)
(111)
837
(1,236)
2019
2018
2017
(618)
127
(122)
(378)
21
8
(962)
250
(14)
112
93
(255)
(103)
(153)
(879)
(565)
32
(120)
18
8
(627)
341
(307)
132
52
(249)
(313)
(378)
(971)
(638)
(111)
(113)
12
16
(834)
(905)
837
128
73
(264)
(271)
(334)
(1,236)
Information about leases is disclosed in note 12 – Right-of-use assets
and lease liabilities.
The analysis of income (expense) from derivative financial
instruments is disclosed in note 23 – Derivative financial instruments
and hedge accounting.
Finance income (expense) with related parties are disclosed in note
36 – Transactions with related parties.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019
230
31 | Income (expense) from investments
SHARE OF PROFIT (LOSS) OF EQUITY-ACCOUNTED INVESTMENTS
More information is provided in note 15 – Investments.
Share of profit or loss of equity accounted investments by industry
segment is disclosed in note 35 – Segment information and
information by geographic area.
OTHER GAIN (LOSS) FROM INVESTMENTS
(€ million)
Dividends
Net gain (loss) on disposals
Other net income (expense)
2019
247
19
15
281
2018
231
22
910
1,163
2017
205
163
(33)
335
Dividend income primarily related to Nigeria LNG Ltd for €186
million and to Saudi European Petrochemical Co for €46 million
(€187 million and €35 million in 2018 and €167 million and €21
million in 2017, respectively).
In 2018, other net income included a gain of €889 million deriving
from the business combination between Eni Norge AS and Point
Resources AS, with the establishment of joint venture the Vår
Energi AS, determined by the difference between the book value of
the investment corresponding to the fair value of the combined net
assets and the book value of the net assets sold.
32 | Income taxes
(€ million)
Current taxes:
- Italian subsidiaries
- subsidiaries of the Exploration & Production segment - outside Italy
- other subsidiaries - outside Italy
Net deferred taxes:
- Italian subsidiaries
- subsidiaries of the Exploration & Production segment - outside Italy
- other subsidiaries - outside Italy
2019
2018
347
4,729
152
5,228
599
(172)
(64)
363
5,591
301
4,906
163
5,370
130
497
(27)
600
5,970
2017
712
3,167
142
4,021
(464)
(162)
72
(554)
3,467
Current income taxes payable by Italian subsidiaries referred to
foreign taxes for €137 million.
The reconciliation between the statutory tax charge calculated
by applying the Italian statutory tax rate of 24% (same amount in
2018 and 2017) and the effective tax charge is the following:
(€ million)
Profit (loss) before taxation
Tax rate (IRES) (%)
Statutory corporation tax charge (credit) on profit or loss
Increase (decrease) resulting from:
- higher tax charges related to subsidiaries outside Italy
- impact pursuant to the write-down of deferred tax assets and recalculation of tax rates
- tax effects related to previous years
- impact pursuant to foreign tax effects of italian entities
- effect due to the tax regime provided for intercompany dividends
- Italian regional income tax (IRAP)
- impact pursuant to redetermination of the Italian Windfall Corporate tax as per Law 7/2009
- effect due to non-taxable gains/losses on sales of investments
- other adjustments
Effective tax charge
2019
5,746
24.0
1,379
2,934
938
147
105
65
25
(2)
4,212
5,591
2018
10,107
24.0
2,426
3,096
261
(24)
46
47
50
(1)
69
3,544
5,970
2017
6,844
24.0
1,643
1,882
(96)
(1)
54
1
77
61
(177)
23
1,824
3,467
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
231
The higher tax charges at non-Italian subsidiaries related to the Exploration & Production segment for €2,934 million (€3,014 million and
€1,811 million in 2018 and in 2017, respectively).
33 | Earnings per share
Basic earnings per ordinary share are calculated by dividing
net profit for the period attributable to Eni’s shareholders by the
weighted average number of ordinary shares issued and outstanding
during the period, excluding treasury shares.
The average number of ordinary shares used for the calculation
of the basic earnings per share in 2019 was 3,592,249,603
(3,601,140,133 in 2018 and 2017).
Diluted earnings per share are calculated by dividing the net profit of
the period attributable to Eni’s shareholders by the weighted average
number of shares fully-diluted, excluding treasury shares, and
including the number of potential shares to be issued in connection
with stock-based compensation plans.
As of December 31, 2019, the shares that could be potentially issued
related the estimation of new share that will vest in connection with
the 2017-2019 long-term monetary incentive plan.
Reconciliation of the weighted average number of shares used for
the calculation for both basic and diluted earnings per share was as
follows:
Weighted average number of shares used for basic earnings per share
Potential share to be issued for ILT incentive plan
Weighted average number of shares used for diluted earnings per share
Eni’s net profit
Basic earnings per share
Diluted earnings per share
2019
3,592,249,603
2,251,406
3,594,501,009
148
0.04
0.04
2018
3,601,140,133
2,782,584
3,603,922,717
4,126
1.15
1.15
2017
3,601,140,133
1,691,413
3,602,831,546
3,374
0.94
0.94
(€ million)
(€ per share)
(€ per share)
34 | Exploration for evaluation of Oil & Gas resources
(€ million)
Revenues related to exploration activity and evaluation
Exploration activity and evaluation costs
- write-off of exploration and evaluation costs
- costs of geological and geophysical studies
Exploration expense for the year
Intangible assets: proved and unproved exploration licence and leasehold property acquisition costs
Tangible assets: capitalized exploration and evaluation costs
Total tangible and intangible assets
Provision for decommissioning related to exploration activity and evaluation
Exploration expenditure (net cash used in investing activivties)
Geological and geophysical costs (cash flow from operating activities)
Total exploration effort
2019
34
214
275
489
1,031
1,563
2,594
109
586
275
861
2018
17
93
287
380
1,081
1,267
2,348
77
463
287
750
2017
9
252
273
525
995
1,371
2,366
81
442
273
715
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019
232
35 | Segment information and information by geographic area
SEGMENT INFORMATION
Eni’s segmental reporting reflects the Group’s operating segments,
whose results are regularly reviewed by the chief operating
decision maker (the CEO) to make decisions about resources to be
allocated to each segment and to assess segment performance.
Segment performance is evaluated based on operating profit or
loss. Other segment information presented to the CEO include
segment revenues and directly attributable assets and liabilities.
As of December 31, 2019, Eni had the following reportable segments:
Exploration & Production: engages in the research, development
and production of crude oil and natural gas, including projects to
build and operate liquefaction plants of LNG;
Gas & Power: engages in supply and marketing of natural gas at
wholesale and retail markets, supply and marketing of LNG and
supply, production and marketing of power at retail and wholesale
markets. Gas & Power is also engaged in supply and marketing of
crude oil and oil products targeting the operational requirements of
Eni’s refining business and in energy commodity trading (including
crude oil, natural gas, oil products, power, emission allowances,
etc.) targeting to both hedge and stabilize the Group's industrial
and commercial margins according to an integrated view and to
optimize margins.
Refining & Marketing and Chemicals: engages in the
manufacturing, supply and distribution and marketing activities of
oil products and chemical products. The results of the Chemicals
business have been aggregated to those of the Refining &
Marketing business in a single reportable segment, because these
two operating segments exhibit similar economic characteristics.
Corporate and Other activities: include the costs of the Group HQ
functions which provide services to the operating subsidiaries,
comprising holding, financing and treasury, IT, HR, real estate, legal
assistance, captive insurance, as well as the results of the Group
environmental
clean-up and remediation activities performed by the subsidiary
Eni Rewind SpA (former Syndial SpA). The Energy Solutions
Department, which engages in developing the renewable energy
business, is an operating segment, which is reported within
Corporate and Other activities because it does not meet the
materiality threshold set by IFRS 8 for separate segment reporting.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 233
e
t
a
r
o
p
r
o
C
r
e
h
t
O
d
n
a
s
e
i
t
i
v
i
t
c
a
s
t
n
e
m
t
s
u
d
A
j
p
u
o
r
g
a
r
t
n
i
f
o
s
t
fi
o
r
p
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a
t
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o
i
t
c
u
d
o
r
P
&
n
o
i
t
a
r
o
l
p
x
E
23,572
(13,073)
10,499
7,417
97
(7,060)
(1,347)
130
(292)
7
68,915
r
e
w
o
P
&
s
a
G
50,015
(11,855)
38,160
699
232
(447)
(83)
46
(1)
(11)
9,176
s
l
a
c
i
m
e
h
C
d
n
a
g
n
i
t
e
k
r
a
M
&
i
g
n
n
fi
e
R
23,334
(2,317)
21,017
(854)
273
(485)
(1,127)
205
(6)
(63)
12,336
1,681
(1,476)
205
(710)
307
(146)
(13)
1
(1)
(21)
1,860
(120)
(51)
32
(492)
4,108
20,164
487
7,852
3,107
4,599
1,333
3,927
(141)
6,996
230
933
231
(14)
25,744
(15,801)
9,943
10,214
235
(6,152)
(1,025)
299
(97)
158
63,051
55,690
(12,581)
43,109
629
53
(408)
(56)
127
(1)
9
9,989
4,972
18,110
494
8,314
25,216
(2,622)
22,594
(380)
274
(399)
(193)
(2)
(67)
11,692
275
4,319
1,589
(1,413)
176
(691)
579
(59)
(18)
211
(21)
30
(168)
1,171
1,303
4,072
(420)
(275)
7,901
215
877
143
(17)
19,525
(12,394)
7,131
7,651
479
(6,747)
(650)
808
(260)
(99)
66,661
50,623
(10,777)
39,846
75
(20)
(345)
(56)
202
(2)
(10)
11,058
22,107
(2,336)
19,771
981
182
(360)
(131)
77
(1)
(57)
11,599
1,234
17,273
509
8,851
321
4,005
1,462
(1,291)
171
(668)
245
(60)
(25)
(27)
29
(101)
1,108
1,447
4,053
(610)
(306)
7,739
142
729
87
(16)
69,881
6,432
858
(8,106)
(2,570)
382
(300)
(88)
91,795
31,645
9,035
36,401
39,139
8,376
75,822
9,983
1,120
(6,988)
(1,292)
426
(100)
(68)
85,483
32,890
7,044
34,540
32,760
9,119
66,919
8,012
886
(7,483)
(862)
1,087
(263)
(267)
89,816
25,112
3,511
33,876
32,973
8,681
Information by segment is as follows:
(€ milioni)
2019
Sales from operations including intersegment sales
Less: intersegment sales
Sales from operations
Operating profit
Net provisions for contingencies
Depreciation and amortization
Impairments of tangible and intangible assets and right-of-use assets
Reversals of tangible and intangible assets
Write-off of tangible and intangible assets
Share of profit (loss) of equity-accounted investments
Identifiable assets(a)
Unallocated assets(b)
Equity-accounted investments
Identifiable liabilities(c)
Unallocated liabilities(d)
Capital expenditure in tangible and intangible assets and prepaid right-of-use assets
2018
Sales from operations including intersegment sales
Less: intersegment sales
Sales from operations
Operating profit
Net provisions for contingencies
Depreciation and amortization
Impairments of tangible and intangible assets
Reversals of tangible and intangible assets
Write-off of tangible and intangible assets
Share of profit (loss) of equity-accounted investments
Identifiable assets(a)
Unallocated assets(b)
Equity-accounted investments
Identifiable liabilities(c)
Unallocated liabilities(d)
Capital expenditure in tangible and intangible assets
2017
Sales from operations including intersegment sales
Less: intersegment sales
Sales from operations
Operating profit
Net provisions for contingencies
Depreciation and amortization
Impairments of tangible and intangible assets
Reversals of tangible and intangible assets
Write-off of tangible and intangible assets
Share of profit (loss) of equity-accounted investments
Identifiable assets(a)
Unallocated assets(b)
Equity-accounted investments
Identifiable liabilities(c)
Unallocated liabilities(d)
Capital expenditure in tangible and intangible assets
(a) Include assets directly associated with the generation of operating profit.
(b) Include assets not directly associated with the generation of operating profit.
(c) Include liabilities directly associated with the generation of operating profit.
(d) Include liabilities not directly associated with the generation of operating profit.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019
234
INFORMATION BY GEOGRAPHICAL AREA
Identifiable assets and investments by geographical area of origin
(€ milioni)
2019
Identifiable assets(a)
Capital expenditure in tangible and intangible assets
and prepaid right-of-use assets
2018
Identifiable assets(a)
Capital expenditure in tangible and intangible assets
2017
Identifiable assets(a)
Capital expenditure in tangible and intangible assets
(a) Includes assets directly associated with the generation of operating profit.
Sales from operations by geographical area of destination
(€ million)
Italy
Other European Union
Rest of Europe
Americas
Asia
Africa
Other areas
n
a
e
p
o
r
u
E
r
e
h
t
O
n
o
i
n
U
l
y
a
t
I
e
p
o
r
u
E
f
o
t
s
e
R
s
a
c
i
r
e
m
A
a
i
s
A
a
c
i
r
f
A
s
a
e
r
a
r
e
h
t
O
l
a
t
o
T
19,346
7,237
1,151
5,230
17,898
40,021
912
91,795
1,402
306
9
1,017
1,685
3,902
55
8,376
18,646
1,424
18,449
1,090
7,086
267
7,706
316
1,031
538
6,160
387
4,546
534
4,406
278
16,910
1,782
36,155
4,533
16,527
898
35,385
5,699
1,109
41
1,183
13
85,483
9,119
89,816
8,681
2019
23,312
18,567
6,931
3,842
8,102
8,998
129
69,881
2018
25,279
20,408
7,052
5,051
9,585
8,246
201
75,822
2017
21,925
19,791
5,911
5,154
7,523
6,428
187
66,919
36 | Transactions with related parties
In the ordinary course of its business, Eni enters into transactions
regarding:
(a) purchase/supply of goods and services and the provision of financing
to joint ventures, associates and non-consolidated subsidiaries;
(b) purchase/supply of goods and services to entities controlled by
the Italian Government;
(c) purchase/supply of goods and services to companies related
to Eni SpA through members of the Board of Directors. Most of
these transactions are exempt from the application of the Eni
internal procedure “Transactions involving interests of Directors
and Statutory Auditors and transactions with related parties”
pursuant to the Consob Regulation, since they relate to ordinary
transactions conducted at market or standard conditions, or
because they fall below the materiality threshold provided for by
the procedure. The solely non-exempted transaction, that was
positively examined and valued in application of the procedure,
concerned the remote monitoring of cars in the "enjoy" initiative
(for an amount of about €1 million) conducted with Vodafone
Italia SpA related to Eni SpA through of a member of the Board of
Directors; and
(d) contributions to non-profit entities correlated to Eni with the
aim to develop solidarity, culture and research initiatives. In
particular these related to: (i) Eni Foundation, established
by Eni as a non-profit entity with the aim of pursuing
exclusively solidarity initiatives in the fields of social
assistance, health, education, culture and environment, as
well as scientific and technological research; and (ii) Eni
Enrico Mattei Foundation, established by Eni with the aim of
enhancing, through studies, research and training initiatives,
knowledge enrichment in the fields of economics, energy and
environment, both at the national and international level.
Transactions with related parties were conducted in the interest
of Eni companies and, with exception of those with entities whose
aim is to develop charitable, cultural and research initiatives, are
related to the ordinary course of Eni’s business.
Investments in subsidiaries, joint arrangements and associates
as of December 31, 2019 are presented in the annex "List of
companies owned by Eni SpA as of December 31, 2019". This
annex includes also the changes in the scope of consolidation.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
TRANSACTIONS AND BALANCES WITH RELATED PARTIES
December 31, 2019
2019
Name
Joint ventures and associates
Agiba Petroleum Co
Angola LNG Supply Services Llc
Coral FLNG SA
Gas Distribution Company of Thessaloniki - Thessaly SA
Saipem Group
Karachaganak Petroleum Operating BV
Mellitah Oil & Gas BV
Petrobel Belayim Petroleum Co
Unión Fenosa Gas SA
Vår Energi AS
Other(*)
Unconsolidated entities controlled by Eni
Eni BTC Ltd
Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation)
Other
Entities controlled by the Government
Enel Group
Italgas Group
Snam Group
Terna Group
GSE - Gestore Servizi Energetici
Other
Other related parties
Groupement Sonatrach – Agip «GSA» and Organe Conjoint
des Opérations «OC SH/FCP»
Total
(*) Each individual amount included herein was lower than €50 million.
Receivables
and other
assets
Payables
and other
liabilities Guarantees Revenues
(€ million)
181
1,168
510
57
482
1
2,399
180
3
14
197
2,596
3
15
75
33
57
50
8
32
106
379
101
5
106
485
185
3
278
40
26
10
542
2
71
13
227
198
171
1,130
1
143
29
1,983
1
25
26
2,009
284
154
229
45
24
19
755
3
71
27
1
3
7
1
63
112
285
14
6
20
305
105
1
71
171
549
12
909
5
75
1,104
74
2,841
2,596
33
1,252
Costs
229
53
503
1,134
365
1,590
6
1,481
87
5,448
18
18
5,466
602
677
1,208
223
468
35
3,213
37
457
9,173
235
Other
operating
(expense)
income
63
(64)
(1)
(1)
(8)
17
11
20
19
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019
236
Name
Joint ventures and associates
Agiba Petroleum Co
Angola LNG Supply Services Llc
Coral FLNG SA
Gas Distribution Company of Thessaloniki - Thessaly SA
Saipem Group
Karachaganak Petroleum Operating BV
Mellitah Oil & Gas BV
Petrobel Belayim Petroleum Co
Unión Fenosa Gas SA
Vår Energi AS
Other(*)
Unconsolidated entities controlled by Eni
Eni BTC Ltd
Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation)
Other
Entities controlled by the Government
Enel Group
Italgas Group
Snam Group
Terna Group
GSE - Gestore Servizi Energetici
Other
Other related parties
Groupement Sonatrach – Agip «GSA» and Organe Conjoint
des Opérations «OC SH/FCP»
Total
(*) Each individual amount included herein was lower than €50 million.
December 31, 2018
2018
Receivables
and other
assets
Payables
and other
liabilities Guarantees Revenues
(€ million)
Other
operating
(expense)
income
Costs
156
51
420
998
502
2,282
62
30
1
1
7
123
111
335
104
4,513
11
7
18
353
118
23
109
150
555
45
1,000
4
13
13
4,526
514
667
1,184
231
588
34
3,218
32
37
(26)
11
11
227
(1)
8
74
308
319
177
1,147
793
57
218
2,392
177
5
14
196
2,588
96
18
171
134
268
2,029
7
100
25
2,848
1
23
24
2,872
151
146
289
47
85
18
736
2
1
14
1
75
27
1
56
4
13
44
236
87
6
93
329
134
5
237
26
67
25
494
1
40
864
140
3,750
2,588
34
1,391
229
8,005
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
2017
Receivables
and other
assets
Payables
and other
liabilities Guarantees Revenues
(€ million)
237
Other
operating
(expense)
income
28
28
28
285
2
15
1
303
Costs
142
951
495
3,168
450
3
140
5,349
14
14
5,363
622
506
681
1,221
212
38
3,280
25
1,094
7,270
57
8,421
169
5
7
181
8,602
1
1
28
2
8
44
202
128
412
7
7
14
426
164
702
18
85
154
16
1,139
1
83
4
121
220
1,205
76
22
1,731
1
23
24
1,755
187
219
180
351
31
21
989
2
145
1
20
36
5
86
63
84
295
77
20
97
392
123
69
14
187
35
50
478
1
39
910
2,891
8,603
1,608
9,198
331
42
530
Name
Joint ventures and associates
Agiba Petroleum Co
Coral FLNG SA
Karachaganak Petroleum Operating BV
Mellitah Oil & Gas BV
Petrobel Belayim Petroleum Co
Saipem Group
Unión Fenosa Gas SA
Other(*)
Unconsolidated entities controlled by Eni
Eni BTC Ltd
Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation)
Other
Entities controlled by the Government
Enel Group
GSE - Gestore Servizi Energetici
Italgas Group
Snam Group
Terna Group
Other
Other related parties
Groupement Sonatrach – Agip «GSA» and Organe Conjoint
des Opérations «OC SH/FCP»
Total
(*) Each individual amount included herein was lower than €50 million.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019
238
The most significant transactions with joint ventures, associates and
unconsolidated subsidiaries concerned:
- Eni’s share of expenses incurred to develop oil fields from Agiba
Petroleum Co, Karachaganak Petroleum Operating BV, Mellitah Oil &
Gas BV, Petrobel Belayim Petroleum Co, Groupement Sonatrach - Agip
«GSA», Organe Conjoint des Opérations «OC SH/FCP» and, only for
Karachaganak Petroleum Operating BV, purchase of crude oil by Eni
Trading & Shipping SpA; services charged to Eni’s associates are
invoiced on the basis of incurred costs;
- a guarantee issued on behalf of Angola LNG Supply Services
Llc to cover the commitments relating to the payment of the
regasification fee;
- supply of upstream specialist services and a guarantee issued
on a pro-quota basis granted to Coral FLNG SA on behalf of the
Consortium TJS for the contractual obligations assumed following
the award of the EPCIC contract for the construction of a floating gas
liquefaction plant (for more information see note 27 – Guarantees,
commitments and risks);
- the acquisition of transport and distribution services from the Gas
Distribution Company of Thessaloniki - Thessaly SA;
- engineering, construction and drilling services by the Saipem
Group mainly for the Exploration & Production segment and
residual guarantees issued by Eni SpA relating to bid bonds and
performance bonds;
- a performance guarantee given on behalf of Unión Fenosa Gas SA
in relation to contractual commitments related to the results of
operations and fair value of derivative financial instruments;
- a guarantee issued in compliance with contractual agreements
in the interest of Vår Energi AS, the supply of upstream specialist
services, the purchase of crude oil, condensates and gas and fair
value of derivative financial instruments;
- a guarantee issued in relation to the construction of an oil pipeline
on behalf of Eni BTC Ltd; and
- services for environmental restoration to Industria Siciliana Acido
Fosforico - ISAF SpA (in liquidation).
The most significant transactions with entities controlled by the Italian
Government concerned:
- sale of fuel, sale and purchase of gas, acquisition of power
distribution services and fair value of derivative financial
instruments with Enel Group;
- acquisition of natural gas transportation, distribution and storage
services with Snam Group and Italgas Group on the basis of tariffs
set by the Italian Regulatory Authority for Energy, Networks and
Environment and purchase and sale with Snam Group of natural gas
for granting the system balancing on the basis of prices referred to
the quotations of the main energy commodities;
- acquisition of domestic electricity transmission service and sale and
purchase of electricity for granting the system balancing on the basis
of prices referred to the quotations of the main energy commodities,
and derivatives on commodities entered to hedge the price risk
related to the utilization of transport capacity rights with Terna Group;
- sale and purchase of electricity, gas, environmental certificates, fair
value of derivative financial instruments, sale of oil products and
storage capacity with GSE - Gestore Servizi Energetici for the setting-
up of a specific stock held by the Organismo Centrale di Stoccaggio
Italiano (OCSIT) according to the Legislative Decree No. 249/2012.
Transactions with other related parties concerned:
- provisions to pension funds of €30 million; and
- contributions and service provisions to Eni Enrico Mattei Foundation
for €6 million and to Eni Foundation for €1 million.
FINANCING TRANSACTIONS AND BALANCES WITH RELATED PARTIES
Name
Joint ventures and associates
Angola LNG Ltd
Cardón IV SA
Coral FLNG SA
Coral South FLNG DMCC
Société Centrale Electrique du Congo SA
Other
Unconsolidated entities controlled by Eni
Other
Entities controlled by the Government
Other
Total
December 31, 2019
2019
(€ million) Receivables
Payables
Guarantees
Gains
Charges
563
253
85
18
919
48
48
4
4
971
5
14
19
28
28
12
12
59
249
1,425
2
1,676
2
20
14
36
77
18
95
1
1
1,676
96
36
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
239
December 31, 2018
2018
(€ million) Receivables
Payables
Guarantees
Gains
Charges
705
108
64
38
915
49
49
964
36
30
494
4
564
25
25
64
8
72
661
245
1,397
22
1,664
95
7
13
115
1,664
115
267
5
9
281
2
2
283
December 31, 2017
2017
(€ million) Receivables
Payables
Guarantees
Gains
Charges
955
101
66
56
48
1,226
60
1
61
1,287
43
3
49
95
9
52
61
8
8
164
233
1,334
56
2
1,625
86
6
13
71
14
190
1
1
1,625
191
1
1
3
3
4
Name
Joint ventures and associates
Angola LNG Ltd
Cardón IV SA
Coral FLNG SA
Coral South FLNG DMCC
Shatskmorneftegaz Sàrl
Société Centrale Electrique du Congo SA
Vår Energi AS
Other
Unconsolidated entities controlled by Eni
Other
Entities controlled by the Government
Enel Group
Other
Total
Name
Joint ventures and associates
Angola LNG Ltd
Coral South FLNG D MCC
Cardón IV SA
Shatskmorneftegaz Sarl
Société Centrale Electrique du Congo SA
Saipem Group
Coral FLNG SA
Other
Unconsolidated entities controlled by Eni
Servizi Fondo Bombole Metano SpA
Other(*)
Entities controlled by the Government
Other
Totale
(*) Each individual amount included herein was lower than €50 million.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019
240
The most significant transactions with joint ventures, associates and
unconsolidated subsidiaries concerned:
- bank debt guarantees issued on behalf of Angola LNG Ltd;
- the financing loan granted to Cardón IV SA for the exploration and
development activities of a gas field in Venezuela;
- financing loans granted to Coral FLNG SA for the construction of a
floating gas liquefaction plant in Area 4 offshore Mozambique (for more
information see note 27 – Guarantees, commitments and risks);
- a bank debt guarantee issued on behalf of Coral South FLNG DMCC as
part of the project financing of the Coral FLNG development project (for
more information see note 27 – Guarantees, commitments and risks);
- the loan granted to Société Centrale Electrique du Congo SA for the
construction of a power plant in Congo.
Impact of transactions and positions with related parties
on the balance sheet, profit and loss account and
statement of cash flows
The impact of transactions and positions with related parties on the
balance sheet accounts consisted of the following:
(€ million)
Other current financial assets
Trade and other receivables
Other current assets
Other non-current financial assets
Other non-current assets
Short-term debt
Current portion of long-term lease liabilities
Trade and other payables
Other current liabilities
Long-term lease liabilities
Other non-current liabilities
December 31, 2019
December 31, 2018
s
e
i
t
r
a
p
d
e
t
a
l
e
R
60
704
219
911
181
46
5
2,663
155
8
23
s
e
i
t
r
a
p
d
e
t
a
e
R
l
49
633
71
915
160
661
3,664
63
%
t
c
a
p
m
I
16.33
4.49
2.52
73.02
25.64
30.29
21.88
1.16
l
a
t
o
T
300
14,101
2,819
1,253
624
2,182
16,747
5,412
1,475
23
1.56
%
t
c
a
p
m
I
15.63
5.47
5.51
77.60
20.78
1.88
0.56
17.13
2.17
0.17
1.43
l
a
t
o
T
384
12,873
3,972
1,174
871
2,452
889
15,545
7,146
4,759
1,611
The impact of transactions with related parties on the profit and loss accounts consisted of the following:
(€ million)
Sales from operations
Other income and revenues
Purchases, services and other
Net (impairment losses) reversals of trade
and other receivables
Payroll and related costs
Other operating income (expense)
Finance income
Finance expense
l
a
t
o
T
69,881
1,160
(50,874)
(432)
(2,996)
287
3,087
(4,079)
2019
2018
2017
s
e
i
t
r
a
p
d
e
t
a
l
e
R
%
t
c
a
p
m
I
l
a
t
o
T
s
e
i
t
r
a
p
d
e
t
a
e
R
l
%
t
c
a
p
m
I
l
a
t
o
T
s
e
i
t
r
a
p
d
e
t
a
e
R
l
1,248
4
(9,173)
1.79
0.34
18.03
75,822
1,116
(55,622)
1,383
8
(8,009)
1.82
0.72
14.40
66,919
4,058
(51,548)
1,567
41
(9,164)
28
(28)
19
96
(36)
..
(415)
0.93
6.62
3.11
0.88
(3,093)
129
3,967
(4,663)
26
(22)
319
115
(283)
..
(913)
0.71
..
2.90
6.07
(2,951)
(32)
3,924
(5,886)
(34)
331
191
(4)
%
t
c
a
p
m
I
2.34
1.01
17.78
1.15
..
4.87
0.07
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
Main cash flows with related parties are provided below:
(€ million)
Revenues and other income
Costs and other expenses
Other operating income (expense)
Net change in trade and other receivables and payables
Net interests
Net cash provided from operating activities
Capital expenditure in tangible and intangible assets
Net change in accounts payable and receivable in relation to investments
Change in financial receivables
Net cash used in investing activities
Change in financial and lease liabilities
Net cash used in financing activities
Total financial flows to related parties
The impact of cash flows with related parties consisted of the following:
241
2019
1,252
(6,869)
19
(839)
81
(6,356)
(2,332)
(339)
(241)
(2,912)
(817)
(817)
(10,085)
2018
1,391
(5,210)
319
683
110
(2,707)
(2,768)
20
(566)
(3,314)
16
16
(6,005)
2017
1,608
(5,360)
331
391
187
(2,843)
(3,838)
425
298
(3,115)
(16)
(16)
(5,974)
2019
2018
2017
s
e
i
t
r
a
p
d
e
t
a
l
e
R
l
a
t
o
T
12,392
(11,413)
(5,841)
(6,356)
(2,912)
(817)
%
t
c
a
p
m
I
..
25.51
13.99
l
a
t
o
T
13,647
(7,536)
(2,637)
s
e
i
t
r
a
p
d
e
t
a
e
R
l
%
t
c
a
p
m
I
l
a
t
o
T
s
e
i
t
r
a
p
d
e
t
a
e
R
l
(2,707)
(3,314)
16
..
43.98
..
10,117
(3,768)
(4,595)
(2,843)
(3,115)
(16)
%
t
c
a
p
m
I
..
82.67
0.35
(€ million)
Net cash provided by operating activities
Net cash used in investing activities
Net cash used in financing activities
37 | Other information about investments40
Information on Eni’s consolidated subsidiaries with
significant non-controlling interest
In 2019 and 2018, Eni did not own any consolidated subsidiaries with a
significant non-controlling interest.
The total shareholders' equity pertaining to non controlling interest
interests as of December 31, 2019, amounted to €61 million (€57
million at December 31, 2018).
Changes in the ownership interest without loss of control
In 2019, Eni acquired a 10% stake of Windirect BV.
In 2018, Eni did not report any changes in ownership interest without
loss or acquisition of control.
(40) Investments in subsidiaries, joint arrangements and associates as of December 31, 2019 are presented in the annex "List of companies owned by Eni SpA as of December 31, 2019". This
annex includes also the changes in the scope of consolidation.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019
242
Principal joint ventures, joint operations and associates as of December 31, 2019
Company name
Joint venture
Vår Energi AS
Saipem SpA
Unión Fenosa Gas SA
Cardón IV SA
Gas Distribution Company of Thessaloniki-
Thessaly SA
Joint operation
Mozambique Rovuma Venture SpA
Raffineria di Milazzo ScpA
GreenStream BV
Blue Stream Pipeline Co BV
Associates
Abu Dhabi Oil Refining Co (Takreer)
Angola LNG Ltd
Coral FLNG SA
Registered office
Country
of operation
Business segment
% ownership
interest
Eni's % of the
investment
Forus
(Norway)
San Donato Milanese (MI)
(Italy)
Madrid
(Spain)
Caracas
(Venezuela)
Ampelokipi-Menemeni
(Greece)
San Donato Milanese (MI)
(Italy)
Milazzo (ME)
(Italy)
Amsterdam
(Netherlands)
Amsterdam
(Netherlands)
Abu Dhabi
(United Arab Emirates)
Hamilton
(Bermuda)
Maputo
(Mozambique)
Norway
Exploration & Production
Italy
Spain
Other activities
Gas & Power
Venezuela
Exploration & Production
Greece
Gas & Power
Mozambique
Exploration & Production
Italy
Libya
Russia
Refining & Marketing
Gas & Power
Gas & Power
United Arab Emirates Refining & Marketing
Angola
Exploration & Production
Mozambique
Exploration & Production
69.60
30.54
50.00
50.00
49.00
35.71
50.00
50.00
74.62
20.00
13.60
25.00
69.60
30.99
50.00
50.00
49.00
35.71
50.00
50.00
74.62
20.00
13.60
25.00
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 243
Main line items of profit and loss and balance sheet related to the principal joint ventures, represented by the amounts included in the reports
accounted under IFRS of each company, are provided in the table below:
(€ million)
Current assets
- of which cash and cash equivalent
Non-current assets
Total assets
Current liabilities
- current financial liabilities
Non-current liabilities
- non-current financial liabilities
Total liabilities
Net equity
Eni's % of the investment
Book value of the investment
Revenues and other income
Operating expense
Depreciation, amortization and impairments
Operating profit
Finance income (expense)
Income (expense) from investments
Profit before income taxes
Income taxes
Net profit
Other comprehensive income
Total other comprehensive income
Net profit attributable to Eni
Dividends received from the joint venture
2019
Vår Energi AS
1,385
182
18,427
19,812
2,374
Saipem SpA
7,012
2,272
5,997
13,009
5,204
Unión
Fenosa Gas SA
585
41
827
1,412
225
Cardón IV SA
208
6
2,383
2,591
255
Gas Distribution
Company
of Thessaloniki-
Thessaly SA
31
12
322
353
24
Other joint
ventures
551
40
1,085
1,636
819
557
3,680
3,147
8,884
4,125
30.99
1,250
9,118
(7,972)
(690)
456
(210)
(18)
228
(130)
98
66
164
4
49
563
493
788
624
50.00
326
1,255
(1,221)
(53)
(19)
(37)
6
(50)
8
(42)
11
(31)
(14)
2,040
1,140
2,295
296
50.00
148
598
(456)
(86)
56
(133)
(77)
(103)
(180)
5
(175)
(90)
33
13,820
3,929
16,194
3,618
69.60
2,518
2,552
(1,015)
(1,208)
329
(1)
328
(258)
70
40
110
49
1,057
9
46
33
70
283
49.00
139
58
(16)
(14)
28
(1)
27
(7)
20
20
10
10
165
354
274
1,173
463
199
270
(277)
(47)
(54)
(14)
(68)
(12)
(80)
(80)
(40)
6
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019
24 4
(€ million)
Current assets
- of which cash and cash equivalent
Non-current assets
Total assets
Current liabilities
- current financial liabilities
Non-current liabilities
- non-current financial liabilities
Total liabilities
Net equity
Eni's % of the investment
Book value of the investment
Revenues and other income
Operating expense
Depreciation, amortization and impairments
Operating profit
Finance income (expense)
Income (expense) from investments
Profit before income taxes
Income taxes
Net profit
Other comprehensive income
Total other comprehensive income
Net profit attributable to Eni
Dividends received from the joint venture
Vår Energi AS Saipem SpA
6,211
1,366
Unión Fenosa
Gas SA
664
2018
Gas Distribution
Company
of Thessaloniki -
Thessaly SA Cardón IV SA
191
32
Lotte Versalis
Elastomers
Co Ltd
56
PetroJunín
SA
368
Other
joint
ventures
130
883
11,407
12,773
608
7,139
366
7,747
5,026
69.60
3,498
1,674
5,466
11,677
4,430
305
3,211
2,646
7,641
4,036
30.99
1,228
8,530
(7,682)
(811)
37
(165)
(88)
(216)
(194)
(410)
(46)
(456)
(146)
107
832
1,496
260
22
581
510
841
655
50.00
335
1,521
(1,461)
(70)
(10)
(31)
9
(32)
(1)
(33)
15
(18)
(23)
40
2,433
2,624
232
2,196
1,410
2,428
196
50.00
98
610
(372)
(137)
101
(208)
(107)
(35)
(142)
6
(136)
(71)
13
302
334
52
2
54
280
49.00
137
53
(16)
(12)
25
25
(8)
17
17
8
8
8
502
558
111
78
297
289
408
150
50.00
75
22
(58)
(30)
(66)
(12)
(78)
(78)
(78)
(39)
253
621
470
34
504
117
40.00
47
112
(100)
(394)
(382)
31
(351)
(19)
(370)
11
(359)
(148)
38
334
464
307
165
126
14
433
31
(2)
731
(697)
(62)
(28)
(5)
(33)
(10)
(43)
(4)
(47)
(21)
11
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
Main line items of profit and loss and balance sheet related to the principal associates represented by the amounts included in the reports
accounted under IFRS of each company are provided in the table below:
245
(€ million)
Current assets
- of which cash and cash equivalent
Non-current assets
Total assets
Current liabilities
- current financial liabilities
Non-current liabilities
- non-current financial liabilities
Total liabilities
Net equity
Eni's % of the investment
Book value of the investment
Revenues and other income
Operating expense
Depreciation, amortization and impairments
Operating profit
Finance income (expense)
Income (expense) from investments
Profit before income taxes
Income taxes
Net profit
Other comprehensive income
Total other comprehensive income
Net profit attributable to Eni
Dividends received from the associate
2019
d
t
L
G
N
L
a
l
o
g
n
A
890
653
9,952
10,842
185
2,135
1,943
2,320
8,522
13.60
1,159
1,552
(549)
(509)
494
(151)
343
343
162
505
47
A
S
G
N
L
F
l
a
r
o
C
241
240
4,119
4,360
230
3,722
3,722
3,952
408
25.00
102
(12)
(12)
5
(7)
8
1
(2)
o
C
g
n
n
fi
e
R
i
l
i
O
i
b
a
h
D
u
b
A
)
r
e
e
r
k
a
T
(
4,659
42
18,868
23,527
8,470
3,694
912
479
9,382
14,145
20.00
2,829
399
(357)
(335)
(293)
(46)
282
(57)
11
(46)
(59)
(105)
(9)
46
s
e
t
a
i
c
o
s
s
a
r
e
h
t
O
838
91
3,259
4,097
585
63
2,677
2,515
3,262
835
264
818
(763)
(28)
27
(2)
35
60
(10)
50
5
55
22
15
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019
246
(€ million)
Current assets
- of which cash and cash equivalent
Non-current assets
Total assets
Current liabilities
- current financial liabilities
Non-current liabilities
- non-current financial liabilities
Total liabilities
Net equity
Eni's % of the investment
Book value of the investment
Revenues and other income
Operating expense
Depreciation, amortization and impairments
Operating profit
Finance income (expense)
Income (expense) from investments
Profit before income taxes
Income taxes
Net profit
Other comprehensive income
Total other comprehensive income
Net profit attributable to Eni
Dividends received from the associate
2018
A
S
G
N
L
F
l
a
r
o
C
109
109
2,434
2,543
117
2,018
2,016
2,135
408
25.00
102
(1)
(1)
(11)
(12)
(12)
16
4
(3)
d
t
L
G
N
L
a
o
g
n
A
l
1,027
698
9,079
10,106
472
1,500
1,328
1,972
8,134
13.60
1,106
1,919
(872)
1,647
2,694
(97)
2,597
2,597
337
2,934
353
s
e
t
a
i
c
o
s
s
a
r
e
h
t
O
926
178
2,296
3,222
785
134
1,755
1,473
2,540
682
241
1,053
(887)
(58)
108
(1)
16
123
(26)
97
17
114
25
25
38 | Public assistance - Italian Law No. 124/2017 and subsequent modifications
Under art. 1, paragraphs 125 and 126, of the Italian Law No. 124/2017 and
subsequent modifications, the disclosures about (i) assistances received
by Eni SpA and its consolidated subsidiaries from Italian public authorities
and entities with the exclusion of listed public controlled companies and
their subsidiaries; (ii) assistances granted by Eni SpA and by its fully
consolidated subsidiaries to companies, persons and public and private
entities, are provided below41.
The following disclosure requirements do not apply to: (i) incentives/
subventions granted to all those entitled in accordance with a general
assistance aid scheme; (ii) consideration in exchange for supplied
goods/services, included sponsorships; (iii) reimbursements and
indemnities paid to persons engaged in professional and orientation
trainings; (iv) continuous training contributions to companies granted
by inter-professional funds established in the legal form of association;
(v) membership fees for the participation to industry trade and
territorial associations, as well as to foundations or similar organizations,
which perform activities linked with the Company’s business; (vi)
costs incurred with reference to social projects linked to the investing
activities of the Company.
Assistances are identified on a cash basis42.
The disclosure includes assistance equal or exceeding €10,000, even
though they are granted through several payments.
Under art. 1, subsection 125-quinquies of Law No. 124/2017, for
received assistance see the information included in the Italian State
aid Register, prepared in accordance with the art. 52 of the Italian
Law 24 December 2012, No. 234. In addition, the Company reports
the contribution received by the Ministry of Education, University and
Research (MIUR) of €1,157,397.
(41) The following disclosures do not include assistance granted by foreign subsidiaries to foreign beneficiaries.
(42) In case of non-monetary economic benefits, the cash basis must be assumed substantially referring to the year in which the benefit was enjoyed.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
The granted assistance provided herein is mainly referred to foundations, associations and other entities for reputational purposes, donations
and support for charitable and solidarity initiatives:
247
Granted subject
Fondazione Eni Enrico Mattei
Fondazione Teatro alla Scala
Eni Foundation
Fondazione Giorgio Cini
WEF - World Economic Forum
Medici con l'Africa (CUAMM Onlus)
Monastero delle Clarisse di S. Maria Maddalena in Matelica
Associazione L'altra Napoli
Council on Foreign Relations
Atlantic Council of the United States, Inc.
World Business Council for Sustainable Development
Associazione Pionieri e Veterani Eni
EITI - Extractive Industries Transparency Initiative
Bruegel
Parrocchia di S. Barbara a San Donato Milanese
Aspen Institute Italia
italiadecide
E4IMPACT Foundation
ONG Volontariato Internazionale per lo Sviluppo (VIS)
Ajuda de Desenvolvimento de Povo para Povo (ADPP)
Center For Strategic & International Studies
The Halo Trust
Politecnico di Milano - Dipartimento di "Scienze e Tecnologie Energetiche e Nucleari"
Foreign Policy Association - USA
The Metropolitan Museum of Art
Associazione Civita
Associazione Amici della Luiss
Centro Studi Americani
Human Foundation
Global Reporting Initiative
AMICAL
Comune Collesalvetti
Associazione Canoa Club Livorno
I Sette Nani – società cooperativa
A.S.D Polisportiva G.S. Rodano
Liceo Classico "Eschilo" - Gela
39 | Significant non-recurring events and operations
In 2019, in 2018 and 2017, Eni did not report any non-recurring events and operations.
40 | Positions or transactions deriving from atypical and/or unusual operations
In 2019, 2018 and 2017 no transactions deriving from atypical and/or unusual operations were reported.
2019 Amount
paid (€)
5,750,060
3,082,352
732,661
500,000
264,085
263,308
200,000
95,000
92,437
84,034
74,824
57,000
52,957
50,000
40,000
35,000
35,000
35,000
32,908
32,908
29,412
26,326
26,000
22,065
22,065
22,000
20,000
20,000
20,000
20,000
19,807
15,000
15,000
15,000
10,000
10,000
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2019 248
41 | Subsequent events
Impact of COVID-19 and current trends in the oil market
The outbreak of a contagious disease known as COVID-19 which
has spread rapidly to many countries in the world at the beginning
of 2020 and is currently ongoing has triggered a sharp sell-off in
energy commodities markets due to a sudden drop in worldwide
consumption of oil, gas and other energy products as a result of
measures taken worldwide to contain the spread of the disease. In
early March 2020, members of the OPEC+ failed to reach a new deal
for additional oil production cuts desired by some participants to
counteract the decrease in demand from Covid 19 effects. These
developments triggered a collapse in crude oil prices. The price of the
Brent crude benchmark has fallen by more than 50% from 65 $/bbl early
in January 2020 to current values; however the average Brent price for the
first quarter 2020 of approximately 51 $/bbl has fallen by a considerably
lower amount over the corresponding period a year ago (down by
approximately 20%). Also, the price of natural gas at the Italian spot market
“PSV”, which is the main benchmark for sales volumes of equity gas
production has fallen in this period, with the average price for first quarter
2020 at approximately 3.7/mmbtu, down by approximately 50% over the
year-ago quarter.
Future trends in crude oil and natural gas prices will greatly depend on
how the current COVID-19 crisis unfolds and on how long it lasts. Under the
worst of the assumptions, the spread of the disease could trigger a global
recession which could materially hit demand for energy products and
prices of energy commodities. This scenario could be further complicated
in case the members of the OPEC+ continue to cease supporting crude
oil prices. These trends could have a material and adverse effect on our
results of operations, cash flow, liquidity and business prospects, including
trends in Eni shares and shareholders’ returns.
We retain some levers of financial flexibility in case of a significant
contraction in cash flow from operations. The Group has established
a liquidity reserve consisting of very liquid sovereign bonds and
corporate securities which amounted to €6.8 billion at the balance
sheet date, which together with cash on hand of approximately €6
billion will cushion the impact of a decline in the Company’s liquidity.
Furthermore, we have as of December 31, 2019, undrawn uncommitted
borrowing facilities amounting to €13,299 million and undrawn long-
term committed borrowing facilities of €4,667 million. Those facilities
bore interest rates reflecting prevailing conditions on the marketplace.
The main financial commitments of 2020 include long-term debt
maturities of approximately €3.2 billion and short-term debt of €2.45
billion, while our take-or-pay obligations under long-term gas contracts
and other similar obligations amount to an estimated €8 billion at our
budget scenario.
The effects of the recent trends in the oil market on the Group’s results
of operations, liquidity and assets are currently under evaluation by
management. This assessment implies the oil price scenario update
and management's actions to counteract the changed environment, the
effects of which, currently not yet determinable, will be accounted for in
future reporting periods.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 249
Supplemental oil and gas information (unaudited)
The following information pursuant to “International Financial
Reporting Standards” (IFRS) is presented in accordance with FASB
Extractive Activities - Oil and Gas (Topic 932). Amounts related to
minority interests are not significant.
CAPITALIZED COSTS
Capitalized costs represent the total expenditures for proved and
unproved mineral interests and related support equipment and
facilities utilized in oil and gas exploration and production activities,
together with related accumulated depreciation, depletion and
amortization. Capitalized costs by geographical area consist of the
following:
(€ million)
2019
Consolidated subsidiaries
Proved property
Unproved property
Support equipment and facilities
Incomplete wells and other
Gross Capitalized Costs
Accumulated depreciation,
depletion and amortization
Net Capitalized Costs
consolidated subsidiaries(a)
Equity-accounted entities
Proved property
Unproved property
Support equipment and facilities
Incomplete wells and other
Gross Capitalized Costs
Accumulated depreciation,
depletion and amortization
Net Capitalized Costs equity-
accounted entities(a)(c)
2018
Consolidated subsidiaries
Proved property
Unproved property
Support equipment and facilities
Incomplete wells and other
Gross Capitalized Costs
Accumulated depreciation,
depletion and amortization
Net Capitalized Costs
consolidated subsidiaries(a)
Equity-accounted entities
Proved property
Unproved property
Support equipment and facilities
Incomplete wells and other
Gross Capitalized Costs
Accumulated depreciation,
depletion and amortization
Net Capitalized Costs equity-
accounted entities(a)(b)
Italy
Rest of
Europe
North
Africa
Sub-Saharan
Egypt
Africa Kazakhstan
Rest of
Asia
America
Australia
and Oceania
Total
17,643
18
384
635
18,680
6,747
323
21
103
7,194
15,512
502
1,549
1,362
18,925
20,691
34
225
359
21,309
43,272
2,361
1,328
2,541
49,502
12,118
11
116
1,165
13,410
11,434
1,592
36
1,006
14,068
15,912
979
23
457
17,371
1,360
194
12
43
1,609
144,689
6,014
3,694
7,671
162,068
(14,604)
(5,778)
(12,802)
(12,879)
(33,237)
(2,652)
(9,100)
(13,465)
(754) (105,271)
4,076
1,416
6,123
8,430
16,265
10,758
4,968
3,906
855
56,797
11,223
2,260
19
945
14,447
(5,287)
9,160
71
8
7
86
(61)
25
1,511
15
1,526
(323)
1,203
2
11
19
32
1,987
7
229
2,223
(20)
(1,124)
12
1,099
14,794
2,271
34
1,215
18,314
(6,815)
11,499
16,569
18
369
653
17,609
6,236
332
21
103
6,692
14,140
456
1,516
1,554
17,666
17,474
56
208
1,504
19,242
40,607
2,311
1,281
2,307
46,506
11,240
3
108
1,382
12,733
12,711
1,530
38
562
14,841
15,347
861
52
595
16,855
1,967
193
12
127
2,299
136,291
5,760
3,605
8,787
154,443
(13,717)
(5,355)
(11,741)
(11,722)
(29,727)
(2,175)
(10,460)
(13,443)
(1,265)
(99,605)
3,892
1,337
5,925
7,520
16,779
10,558
4,381
3,412
1,034
54,838
9,102
1,045
25
364
10,536
(4,543)
5,993
58
6
10
74
(54)
20
1,481
10
1,491
(266)
1,225
2
11
19
32
1,912
7
224
2,143
(19)
(1,052)
13
1,091
12,555
1,056
38
627
14,276
(5,934)
8,342
(a) The amounts include net capitalized financial charges totalling €878 million in 2019 and €831 million in 2018 for the consolidates subsidiaries and €166 million in 2019 and €180
million in 2018 for equity-accounted entities.
(b) Includes Vår Energi AS asset fair value.
(c) Includes allocation at fair value of the assets purchased by Vår Energi AS.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | SUPPLEMENTAL OIL AND GAS INFORMATIONEni Annual Report 2019
250
COSTS INCURRED
Costs incurred represent amounts both capitalized and expensed in
connection with oil and gas producing activities. Costs incurred by
geographical area consist of the following:
(€ million)
2019
Consolidated subsidiaries
Proved property acquisitions
Unproved property acquisitions
Exploration
Development(a)
Total costs incurred
consolidated subsidiaries
Equity-accounted entities
Proved property acquisitions
Unproved property acquisitions
Exploration
Development(b)
Total costs incurred
equity-accounted entities(c)
2018
Consolidated subsidiaries
Proved property acquisitions
Unproved property acquisitions
Exploration
Development(a)
Total costs incurred
consolidated subsidiaries
Equity-accounted entities
Proved property acquisitions
Unproved property acquisitions
Exploration
Development(b)
Total costs incurred
equity-accounted entities
2017
Consolidated subsidiaries
Proved property acquisitions
Unproved property acquisitions
Exploration
Development(a)
Total costs incurred
consolidated subsidiaries
Equity-accounted entities
Proved property acquisitions
Unproved property acquisitions
Exploration
Development(b)
Total costs incurred
equity-accounted entities
Italy
Rest of
Europe
North
Africa
Sub - Saharan
Egypt
Africa Kazakhstan
Rest
of Asia
America
Australia
and Oceania
20
1,098
1,118
62
230
292
1,054
1,178
125
1,574
3,931
135
101
749
1
94
1,589
985
1,684
4
4
26
382
408
106
557
663
43
445
488
102
2,216
2,318
2
3
5
31
251
282
242
364
606
1
1
77
785
862
110
3,041
3,151
2
2
206
1,959
2,165
5
5
66
1,379
1,445
5
65
1,939
2,009
9
9
23
232
1,199
144
97
106
879
1,454
1,226
15
481
496
(1)
(1)
382
487
182
589
1,640
103
103
76
714
790
90
4
94
37
37
215
340
555
(16)
(16)
106
292
398
48
48
3
92
95
3
246
249
39
43
82
7
36
43
5
14
19
(a) Includes the abandonment costs of the assets for €2,069 million in 2019, negative for €517 million in 2018, asset for €355 million in 2017.
(b) Includes the abandonment costs of the assets for €838 million in 2019, negative €22 million in 2018, negative for €23 million in 2017.
(c) Includes allocation at fair value of the assets purchased by Vår Energi AS.
Total
144
256
875
8,227
9,502
1,054
1,178
124
1,620
3,976
382
487
750
6,036
7,655
105
(13)
92
5
715
7,646
8,366
91
63
154
CONSOLIDATED FINANCIAL STATEMENTS 2019 | SUPPLEMENTAL OIL AND GAS INFORMATION
251
RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES
Results of operations from oil and gas producing activities represent
only those revenues and expenses directly associated with such
activities, including operating overheads. These amounts do not
include any allocation of interest expenses or general corporate
overheads and, therefore, are not necessarily indicative of the
contributions to consolidated net earnings of Eni. Related income
taxes are calculated by applying the local income tax rates to the
pre-tax income from production activities. Eni is party to certain
Production Sharing Agreements (PSAs), whereby a portion of Eni’s
share of oil and gas production is withheld and sold by its joint
venture partners which are state owned entities, with proceeds
being remitted to the state to meet Eni’s PSA related tax liabilities.
Revenue and income taxes include such taxes owed by Eni but paid
by state-owned entities out of Eni’s share of oil and gas production.
Results of operations from oil and gas producing activities by
geographical area consist of the following:
(€ million)
2019
Consolidated subsidiaries
Revenues:
- sales to consolidated entities
- sales to third parties
Total revenues
Production costs
Transportation costs
Production taxes
Exploration expenses
D.D. & A. and Provision for
abandonment(a)
Other income (expenses)
Pretax income from producing
activities
Income taxes
Results of operations from
E&P activities of consolidated
subsidiaries(b)
Equity-accounted entities
Revenues:
- sales to consolidated entities
- sales to third parties
Total revenues
Production costs
Transportation costs
Production taxes
Exploration expenses
D.D. & A. and Provision for
abandonment
Other income (expenses)
Pretax income from producing
activities
Income taxes
Results of operations from E&P
activities of equity-accounted
entities
Italy
Rest of
Europe
North
Africa
Sub-Saharan
Egypt
Africa Kazakhstan
Rest
of Asia
America
Australia
and Oceania
Total
1,493
1,493
(391)
(5)
(183)
(25)
(944)
(337)
(392)
148
618
30
648
(181)
(31)
(51)
(201)
(16)
168
(11)
1,081
4,084
5,165
(520)
(60)
(263)
(30)
(839)
(452)
3,001
(2,561)
3,715
3,715
(330)
(10)
(10)
(978)
(433)
1,954
(839)
4,576
944
5,520
(847)
(39)
(483)
(90)
(3,060)
(502)
499
(268)
1,195
766
1,961
(255)
(158)
(39)
(444)
(71)
994
(326)
2,367
149
2,516
(256)
(4)
(252)
(170)
(820)
(76)
938
(719)
825
180
1,005
(273)
(15)
(7)
(31)
(607)
(86)
(14)
(5)
5
227
232
(43)
(6)
(43)
(97)
(1)
42
(31)
12,160
10,095
22,255
(3,096)
(322)
(1,194)
(489)
(7,990)
(1,974)
7,190
(4,612)
(244)
157
440
1,115
231
668
219
(19)
11
2,578
1,080
677
1,757
(336)
(84)
(47)
(722)
(237)
331
(179)
152
15
15
(8)
(1)
(2)
(1)
(1)
2
(2)
207
207
(24)
(11)
(7)
(70)
(28)
67
67
315
315
(25)
(81)
(51)
(133)
25
(54)
(3)
(3)
(3)
(29)
1,080
1,214
2,294
(393)
(96)
(90)
(47)
(844)
(402)
422
(235)
187
(a) Includes asset net impairment amounting to €1,217 million.
(b) Results of operations exclude revenues, DD&A and income taxes associated with 3.8 million boe as part of a long-term supply agreement to a state-owned national oil company,
whereby the buyer has paid the price without lifting the underlying volume in exercise of the take-or-pay clause. The price collected by the buyer has been recognized as revenues in the
segment information of the E&P sector prepared in accordance with IFRS and DD&A and income taxes have been accrued accordingly, because the Group performance obligation under
the contract has been fulfilled and it is very likely that the buyer will not redeem its contractual right to lift within the contractual terms.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | SUPPLEMENTAL OIL AND GAS INFORMATIONEni Annual Report 2019
252
(€ million)
2018
Consolidated subsidiaries
Revenues:
- sales to consolidated entities
- sales to third parties
Total revenues
Production costs
Transportation costs
Production taxes
Exploration expenses
D.D. & A. and Provision for
abandonment(a)
Other income (expenses)
Pretax income from producing
activities
Income taxes
Results of operations from
E&P activities of consolidated
subsidiaries
Equity-accounted entities
Revenues:
- sales to consolidated entities
- sales to third parties
Total revenues
Production costs
Transportation costs
Production taxes
Exploration expenses
D.D. & A. and Provision for
abandonment
Other income (expenses)
Pretax income from producing
activities
Income taxes
Results of operations from E&P
activities of equity-accounted
entities
Italy
Rest of
Europe
North
Africa
Sub-Saharan
Egypt
Africa Kazakhstan
Rest
of Asia
America
Australia
and Oceania
Total
2,120
2,120
(402)
(8)
(171)
(25)
(281)
(442)
791
(170)
2,740
494
3,234
(488)
(142)
(85)
(664)
(193)
1,277
3,741
5,018
(363)
(50)
(243)
(48)
(582)
(101)
1,662
(1,070)
3,631
(2,494)
3,207
3,207
(343)
(11)
(22)
(795)
(239)
1,797
(542)
4,701
830
5,531
(974)
(42)
(435)
(44)
(2,490)
(1,126)
420
(264)
1,140
769
1,909
(269)
(136)
(3)
(387)
(67)
1,047
(308)
1,902
493
2,395
(220)
(7)
(191)
(79)
(941)
(135)
822
(678)
621
592
1,137
1,255
156
739
144
934
50
984
(234)
(16)
(69)
(594)
(54)
17
7
24
420
420
(36)
(2)
(114)
(222)
(122)
(76)
(35)
6
6
(2)
(235)
(3)
(25)
(259)
(2)
(261)
(111)
4
190
194
(48)
(6)
(5)
(67)
14,818
9,774
24,592
(3,341)
(412)
(1,046)
(380)
(6,801)
(2,357)
68
(26)
10,255
(5,545)
42
4,710
698
698
(79)
(31)
(143)
(241)
(2)
(173)
29
(40)
(11)
15
15
(7)
(1)
(3)
(1)
2
5
(3)
2
(6)
(1)
(7)
(7)
257
257
(34)
(28)
(26)
224
(27)
366
366
(a) Includes asset net impairment amounting to €726 million.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | SUPPLEMENTAL OIL AND GAS INFORMATION
253
(€ million)
2017
Consolidated subsidiaries
Revenues:
- sales to consolidated entities
- sales to third parties
Total revenues
Production costs
Transportation costs
Production taxes
Exploration expenses
D.D. & A. and Provision for
abandonment(a)
Other income (expenses)
Pretax income from producing
activities
Income taxes
Results of operations from
E&P activities of consolidated
subsidiaries
Equity-accounted entities
Revenues:
- sales to consolidated entities
- sales to third parties
Total revenues
Production costs
Transportation costs
Production taxes
Exploration expenses
D.D. & A. and Provision for
abandonment
Other income (expenses)
Pretax income from producing
activities
Income taxes
Results of operations from E&P
activities of equity-accounted
entities
Italy
Rest of
Europe
North
Africa
Sub-Saharan
Egypt
Africa Kazakhstan
Rest
of Asia
America
Australia
and Oceania
Total
1,619
1,619
(332)
(5)
(130)
(26)
(465)
1,563
2,224
(299)
1,897
481
2,378
(523)
(164)
(122)
(838)
(141)
590
(216)
1,056
3,184
4,240
(455)
(49)
(200)
(22)
(679)
(162)
2,673
(1,978)
2,128
2,128
(303)
(11)
(191)
(767)
690
1,546
(214)
3,888
547
4,435
(952)
(34)
(331)
(60)
(2,063)
(716)
279
(38)
681
713
1,394
(271)
(125)
(289)
(221)
488
(223)
911
291
1,202
(202)
(4)
(11)
(61)
(765)
(84)
75
(67)
932
96
1,028
(258)
(54)
(39)
(577)
(342)
(242)
(38)
3
168
171
(48)
(5)
(4)
(59)
2
57
(23)
10,987
7,608
18,595
(3,344)
(446)
(677)
(525)
(6,502)
589
7,690
(3,096)
1,925
374
695
1,332
241
265
8
(280)
34
4,594
14
14
(6)
(2)
(2)
(1)
(2)
1
(1)
(1)
(2)
(3)
(3)
129
129
(19)
(18)
(8)
(54)
26
56
56
22
22
(9)
(13)
(13)
3
(10)
(4)
517
517
(39)
(1)
(146)
(271)
(199)
(139)
(20)
(14)
(159)
682
682
(73)
(21)
(156)
(14)
(339)
(174)
(95)
(25)
(120)
(a) Includes asset net reversal amounting to €158 million.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | SUPPLEMENTAL OIL AND GAS INFORMATIONEni Annual Report 2019
254
OIL AND NATURAL GAS RESERVES
Eni’s criteria concerning evaluation and classification of proved
developed and undeveloped reserves follow Regulation S-X 4-10 of the
US Securities and Exchange Commission and have been disclosed in
accordance with FASB Extractive Activities - Oil and Gas (Topic 932).
Proved oil and gas reserves are those quantities of oil and gas, which,
by analysis of geoscience and engineering data, can be estimated
with reasonable certainty to be economically producible, from a given
date forward, from known reservoirs, and under existing economic
conditions, operating methods, and government regulations, prior
to the time at which contracts providing the right to operate expire,
unless evidence indicates that renewal is reasonably certain,
regardless of whether deterministic or probabilistic methods are used
for the estimation. The project to extract the hydrocarbons must have
commenced or the operator must be reasonably certain that it will
commence the project within a reasonable time. Existing economic
conditions include prices and costs at which economic producibility
from a reservoir is to be determined. The price shall be the average
price during the 12-month period prior to the ending date of the period
covered by the report, determined as an un-weighted arithmetic
average of the first-day-of-the-month price for each month within
such period, unless prices are defined by contractual arrangements,
excluding escalations based upon future conditions.
In 2019, the average price for the marker Brent crude oil was $63 per
barrel.
Net proved reserves exclude interests and royalties owned by others.
Proved reserves are classified as either developed or undeveloped.
Developed oil and gas reserves are reserves that can be expected
to be recovered through existing wells with existing equipment and
operating methods or in which the cost of the required equipment is
relatively minor compared to the cost of a new well. Undeveloped oil
and gas reserves are reserves of any category that are expected to be
recovered from new wells on undrilled acreage, or from existing wells
where a relatively major expenditure is required for recompletion.
Eni has its proved reserves audited on a rotational basis by
independent oil engineering companies43. The description of
qualifications of the person primarily responsible of the reserves audit
is included in the third party audit report44.
In the preparation of their reports, independent evaluators rely,
without independent verification, upon data furnished by Eni with
respect to property interest, production, current costs of operation and
development, sale agreements, prices and other factual information
and data that were accepted as represented by the independent
evaluators. These data, equally used by Eni in its internal process,
include logs, directional surveys, core and PVT (Pressure Volume
Temperature) analysis, maps, oil/gas/water production/injection
data of wells, reservoir studies and technical analysis relevant to
field performance, long-term development plans, future capital and
operating costs. In order to calculate the economic value of Eni
equity reserves, actual prices applicable to hydrocarbon sales, price
adjustments required by applicable contractual arrangements, and
other pertinent information are provided.
In 2019, Ryder Scott Company, DeGolyer and MacNaughton provided
an independent evaluation of about 31% of Eni’s total proved reserves
as of December 31, 201945, confirming, as in previous years, the
reasonableness of Eni’s internal evaluations.
In the three years period from 2017 to 2019, 86% of Eni’s total proved
reserves were subject to independent evaluation. As of December 31,
2019, the principal property not subjected to independent evaluation
in the last three years was Zohr.
Eni operates under production sharing agreements in several of
the foreign jurisdictions where it has oil and gas exploration and
production activities. Reserves of oil and natural gas to which Eni is
entitled under PSA arrangements are shown in accordance with Eni’s
economic interest in the volumes of oil and natural gas estimated
to be recoverable in future years. Such reserves include estimated
quantities allocated to Eni for recovery of costs, income taxes owed by
Eni but settled by its joint venture partners (which are state-owned
entities) out of Eni’s share of production and Eni’s net equity share
after cost recovery. Proved oil and gas reserves associated with PSAs
represented 57%, 61% and 60% of total proved reserves as of December
31, 2019, 2018 and 2017, respectively, on an oil-equivalent basis.
Similar effects as PSAs apply to service contracts; proved reserves
associated with such contracts represented 3%, 3% and 4% of total
proved reserves on an oil-equivalent basis as of December 31, 2019,
2018 and 2017, respectively.
Oil and gas reserves quantities include: (i) oil and natural gas
quantities in excess of cost recovery which the Company has an
obligation to purchase under certain PSAs with governments or
authorities, whereby the Company serves as producer of reserves.
Reserves volumes associated with oil and gas deriving from such
obligation represent 4%, 4% and 1.6% of total proved reserves as of
December 31, 2019, 2018 and 2017, respectively, on an oil equivalent
basis; (ii) volumes of natural gas used for own consumption; (iii) the
quantities of hydrocarbons related to the Angola LNG plant.
Numerous uncertainties are inherent in estimating quantities of
proved reserves, in projecting future productions and development
expenditures. The accuracy of any reserve estimate is a function
of the quality of available data and engineering and geological
interpretation and evaluation. The results of drilling, testing and
production after the date of the estimate may require substantial
upward or downward revisions. In addition, changes in oil and natural
gas prices have an effect on the quantities of Eni’s proved reserves
since estimates of reserves are based on prices and costs relevant to
the date when such estimates are made. Consequently, the evaluation
of reserves could also significantly differ from actual oil and natural
gas volumes that will be produced.
The following table presents yearly changes in estimated proved
reserves, developed and undeveloped, of crude oil (including
condensate and natural gas liquids) and natural gas as of December
31, 2019, 2018 and 2017.
(43) From 1991 to 2002 DeGolyer and McNaughton, from 2003 also Ryder Scott. In 2018 an independent evaluation was provided also by Societé Generale de Surveillance (SGS).
(44) See “Item 19 – Exhibits”.
(45) Including reserves of equity-accounted investments.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | SUPPLEMENTAL OIL AND GAS INFORMATION 255
CRUDE OIL (INCLUDING CONDENSATE AND NATURAL GAS LIQUIDS)
(million barrels)
2019
Consolidated subsidiaries
Reserves at December 31, 2018
of which: developed
undeveloped
Purchase of Minerals in Place
Revisions of Previous Estimates
Improved Recovery
Extensions and Discoveries
Production
Sales of Minerals in Place(a)
Reserves at December 31, 2019
Equity-accounted entities
Reserves at December 31, 2018
of which: developed
undeveloped
Purchase of Minerals in Place
Revisions of Previous Estimates
Improved Recovery
Extensions and Discoveries
Production
Sales of Minerals in Place
Reserves at December 31, 2019
Reserves at December 31, 2019
Developed
consolidated subsidiaries
equity-accounted entities
Undeveloped
consolidated subsidiaries
equity-accounted entities
Italy
Rest of
Europe
North
Africa
Sub-Saharan
Egypt
Africa Kazakhstan
Rest
of Asia
America
Australia
and Oceania
Total
208
156
52
5
(19)
194
194
137
137
57
57
48
44
4
1
(8)
41
297
154
143
109
45
6
(27)
(6)
424
465
256
37
219
209
4
205
493
317
176
37
(62)
279
153
126
10
2
(27)
468
264
11
11
2
(1)
12
480
313
301
12
167
167
264
149
149
115
115
718
551
167
46
21
(90)
(1)
694
12
8
4
(2)
10
704
526
519
7
178
175
3
704
587
117
79
(37)
476
252
224
45
2
(32)
746
491
746
682
682
64
64
491
245
245
246
246
252
143
109
29
(16)
9
(20)
(29)
225
37
32
5
(5)
(1)
31
256
179
148
31
77
77
5
5
(4)
1
1
1
1
3,183
2,208
975
29
203
34
(295)
(30)
3,124
357
205
152
109
42
6
(31)
(6)
477
3,601
2,488
2,219
269
1,113
905
208
(a) Includes 0.6 Mboe as part of a long-term supply agreement to a state-owned national oil company, whereby the buyer has paid the price without lifting the underlying volume in
exercise of the take-or-pay clause because it is very likely that the buyer will not redeem its contractual right to lift (make up) the volume paid.
CONSOLIDATED FINANCIAL STATEMENTS 2019 | SUPPLEMENTAL OIL AND GAS INFORMATIONEni Annual Report 2019
256
(million barrels)
2018
Consolidated subsidiaries
Reserves at December 31, 2017
of which: developed
undeveloped
Purchase of Minerals in Place
Revisions of Previous Estimates
Improved Recovery
Extensions and Discoveries
Production
Sales of Minerals in Place
Reserves at December 31, 2018
Equity-accounted entities
Reserves at December 31, 2017
of which: developed
undeveloped
Purchase of Minerals in Place
Revisions of Previous Estimates
Improved Recovery
Extensions and Discoveries
Production
Sales of Minerals in Place
Reserves at December 31, 2018
Reserves at December 31, 2018
Developed
consolidated subsidiaries
equity-accounted entities
Undeveloped
consolidated subsidiaries
equity-accounted entities
Italy
Rest of
Europe
North
Africa
Sub-Saharan
Egypt
Africa Kazakhstan
Rest
of Asia
America
Australia
and Oceania
Total
215
169
46
15
(22)
208
208
156
156
52
52
360
219
141
6
(40)
(278)
48
297
297
345
198
44
154
147
4
143
476
306
170
73
(56)
493
12
12
(1)
11
504
328
317
11
176
176
280
203
77
21
7
(28)
(1)
279
279
153
153
126
126
764
546
218
30
13
(89)
718
12
6
6
1
(1)
12
730
559
551
8
171
167
4
766
547
219
(27)
(35)
232
81
151
319
(54)
6
1
(28)
704
476
704
587
587
117
117
476
252
252
224
224
162
144
18
23
86
(19)
252
136
25
111
(96)
(3)
37
289
175
143
32
114
109
5
7
5
2
(1)
(1)
5
5
5
5
3,262
2,220
1,042
319
86
13
100
(318)
(279)
3,183
160
43
117
297
(95)
(5)
357
3,540
2,413
2,208
205
1,127
975
152
CONSOLIDATED FINANCIAL STATEMENTS 2019 | SUPPLEMENTAL OIL AND GAS INFORMATION
257
(million barrels)
2017
Consolidated subsidiaries
Reserves at December 31, 2016
of which: developed
undeveloped
Purchase of Minerals in Place
Revisions of Previous Estimates
Improved Recovery
Extensions and Discoveries
Production
Sales of Minerals in Place
Reserves at December 31, 2017
Equity-accounted entities
Reserves at December 31, 2016
of which: developed
undeveloped
Purchase of Minerals in Place
Revisions of Previous Estimates
Improved Recovery
Extensions and Discoveries
Production
Sales of Minerals in Place
Reserves at December 31, 2017
Reserves at December 31, 2017
Developed
consolidated subsidiaries
equity-accounted entities
Undeveloped
consolidated subsidiaries
equity-accounted entities
Italy
Rest of
Europe
North
Africa
Sub-Saharan
Egypt
Africa Kazakhstan
Rest
of Asia
America
Australia
and Oceania
Total
176
132
44
59
(20)
264
228
36
29
1
103
(37)
215
360
215
169
169
46
46
360
219
219
141
141
454
287
167
73
6
1
(58)
476
13
13
(1)
12
488
318
306
12
170
170
281
205
76
21
7
(26)
(3)
280
280
203
203
77
77
809
507
302
2
31
18
(90)
(6)
764
15
8
7
(2)
(1)
12
776
552
546
6
224
218
6
767
556
211
29
(30)
307
124
183
(69)
9
4
(19)
766
232
766
547
547
219
219
232
81
81
151
151
163
143
20
19
3
(23)
162
140
22
118
1
(5)
136
298
169
144
25
129
18
111
9
8
1
(1)
(1)
7
7
5
5
2
2
3,230
2,190
1,040
2
191
23
129
(304)
(9)
3,262
168
43
125
(1)
(7)
160
3,422
2,263
2,220
43
1,159
1,042
117
CONSOLIDATED FINANCIAL STATEMENTS 2019 | SUPPLEMENTAL OIL AND GAS INFORMATIONEni Annual Report 2019
258
NATURAL GAS
(billion cubic feet)
2019
Consolidated subsidiaries
Reserves at December 31, 2018
of which: developed
undeveloped
Purchase of Minerals in Place
Revisions of Previous Estimates
Improved Recovery
Extensions and Discoveries
Production
Sales of Minerals in Place(a)
Reserves at December 31, 2019
Equity-accounted entities
Reserves at December 31, 2018
of which: developed
undeveloped
Purchase of Minerals in Place
Revisions of Previous Estimates
Improved Recovery
Extensions and Discoveries
Production
Sales of Minerals in Place
Reserves at December 31, 2019
Reserves at December 31, 2019
Developed
consolidated subsidiaries
equity-accounted entities
Undeveloped
consolidated subsidiaries
equity-accounted entities
Italy
Rest of
Europe
North
Africa
Sub-Saharan
Egypt
Africa Kazakhstan
Rest
of Asia
America
Australia
and Oceania
Total
1,199
980
219
(310)
(137)
752
752
657
657
95
95
320
300
20
4
2
(64)
262
360
276
84
405
76
(2)
(67)
772
1,034
839
242
597
195
20
175
2,890
1,447
1,443
5,275
3,331
1,944
3,506
1,871
1,635
1,989
1,846
143
1,217
822
395
267
467
747
79
104
(419)
(551)
2,738
5,191
14
14
1
(1)
14
2,752
1,388
1,374
14
1,364
1,364
5,191
4,777
4,777
414
414
78
(210)
(18)
4,103
310
57
253
13
(36)
287
4,390
1,946
1,858
88
2,444
2,245
199
(99)
1,969
274
(198)
(48)
1,349
1,969
1,969
1,969
1,349
685
685
664
664
277
154
123
7
(23)
4
(24)
(1)
240
1,716
1,716
1
(69)
1,648
1,888
1,834
186
1,648
54
54
651
452
199
(108)
(36)
507
507
322
322
185
185
17,324
11,203
6,121
7
1,227
358
(1,738)
(67)
17,111
2,400
2,063
337
405
91
(2)
(173)
2,721
19,832
14,417
12,070
2,347
5,415
5,041
374
(a) Includes 17.6 bcf as part of a long-term supply agreement to a state-owned national oil company, whereby the buyer has paid the price without lifting the underlying volume in
exercise of the take-or-pay clause because it is very likely that the buyer will not redeem its contractual right to lift (make up) the volume paid
CONSOLIDATED FINANCIAL STATEMENTS 2019 | SUPPLEMENTAL OIL AND GAS INFORMATION
259
(billion cubic feet)
2018
Consolidated subsidiaries
Reserves at December 31, 2017
of which: developed
undeveloped
Purchase of Minerals in Place
Revisions of Previous Estimates
Improved Recovery
Extensions and Discoveries
Production
Sales of Minerals in Place
Reserves at December 31, 2018
Equity-accounted entities
Reserves at December 31, 2017
of which: developed
undeveloped
Purchase of Minerals in Place
Revisions of Previous Estimates
Improved Recovery
Extensions and Discoveries
Production
Sales of Minerals in Place
Reserves at December 31, 2018
Reserves at December 31, 2018
Developed
consolidated subsidiaries
equity-accounted entities
Undeveloped
consolidated subsidiaries
equity-accounted entities
Italy
Rest of
Europe
North
Africa
Sub-Saharan
Egypt
Africa Kazakhstan
Rest
of Asia
America
Australia
and Oceania
Total
1,131
987
144
138
86
(156)
1,199
1,199
980
980
219
219
896
771
125
50
(162)
(464)
320
360
360
680
576
300
276
104
20
84
3,145
1,233
1,912
4,351
1,421
2,930
3,660
1,693
1,967
2,108
1,878
230
219
2,238
23
(22)
(474)
2,890
(445)
(869)
5,275
7
(184)
(97)
3,506
1,989
1,065
862
203
69
81
205
(201)
(2)
1,217
14
14
2
(2)
14
2,904
1,461
1,447
14
1,443
1,443
5,275
3,331
3,331
1,944
1,944
349
83
266
(6)
(33)
310
3,816
1,928
1,871
57
1,888
1,635
253
1,989
1,846
1,846
143
143
1,217
822
822
395
395
225
171
54
45
76
(43)
(26)
277
1,819
1,819
(22)
(81)
1,716
1,993
1,870
154
1,716
123
123
709
519
190
(16)
(42)
651
651
452
452
199
199
17,290
9,535
7,755
69
2,756
374
(1,804)
(1,361)
17,324
2,182
1,916
266
360
(26)
(116)
2,400
19,724
13,266
11,203
2,063
6,458
6,121
337
CONSOLIDATED FINANCIAL STATEMENTS 2019 | SUPPLEMENTAL OIL AND GAS INFORMATIONEni Annual Report 2019
260
(billion cubic feet)
2017
Consolidated subsidiaries
Reserves at December 31, 2016
of which: developed
undeveloped
Purchase of Minerals in Place
Revisions of Previous Estimates
Improved Recovery
Extensions and Discoveries
Production
Sales of Minerals in Place
Reserves at December 31, 2017
Equity-accounted entities
Reserves at December 31, 2016
of which: developed
undeveloped
Purchase of Minerals in Place
Revisions of Previous Estimates
Improved Recovery
Extensions and Discoveries
Production
Sales of Minerals in Place
Reserves at December 31, 2017
Reserves at December 31, 2017
Developed
consolidated subsidiaries
equity-accounted entities
Undeveloped
consolidated subsidiaries
equity-accounted entities
Italy
Rest of
Europe
North
Africa
Sub-Saharan
Egypt
Africa Kazakhstan
Rest
of Asia
America
Australia
and Oceania
Total
977
845
132
315
(161)
878
801
77
163
29
(174)
3,738
1,732
2,006
66
(19)
(640)
1,131
896
3,145
5,520
799
4,721
969
64
(315)
(1,887)
4,351
15
15
(1)
14
3,159
1,247
1,233
14
1,912
1,912
4,351
1,421
1,421
2,930
2,930
1,131
987
987
144
144
896
771
771
125
125
2,767
1,651
1,116
1
134
1,839
(162)
(919)
3,660
368
104
264
13
(32)
349
4,009
1,776
1,693
83
2,233
1,967
266
2,485
2,239
246
1,003
280
723
353
338
15
(281)
188
(61)
(96)
(126)
4
(71)
2,108
1,065
225
4
4
3,484
1,782
1,702
741
559
182
6
(38)
709
18,462
9,244
9,218
1
1,499
(19)
1,936
(1,783)
(2,806)
17,290
3,871
1,905
1,966
(1,565)
(1,552)
(4)
(100)
2,108
1,878
1,878
230
230
1,065
862
862
203
203
1,819
2,044
1,990
171
1,819
54
54
(137)
2,182
19,472
11,451
9,535
1,916
8,021
7,755
266
709
519
519
190
190
CONSOLIDATED FINANCIAL STATEMENTS 2019 | SUPPLEMENTAL OIL AND GAS INFORMATION
261
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
Estimated future cash inflows represent the revenues that would be
received from production and are determined by applying the year-end
average prices during the years ended.
Future price changes are considered only to the extent provided by
contractual arrangements. Estimated future development and production
costs are determined by estimating the expenditures to be incurred in
developing and producing the proved reserves at the end of the year.
Neither the effects of price and cost escalations nor expected future
changes in technology and operating practices have been considered.
The standardized measure is calculated as the excess of future
cash inflows from proved reserves less future costs of producing
and developing the reserves, future income taxes and a yearly 10%
discount factor.
Future production costs include the estimated expenditures related to
the production of proved reserves plus any production taxes without
consideration of future inflation. Future development costs include
the estimated costs of drilling development wells and installation of
production facilities, plus the net costs associated with dismantlement
and abandonment of wells and facilities, under the assumption that
year-end costs continue without considering future inflation. Future
income taxes were calculated in accordance with the tax laws of the
Countries in which Eni operates.
The standardized measure of discounted future net cash flows,
related to the preceding proved oil and gas reserves, is calculated in
accordance with the requirements of FASB Extractive Activities - Oil
and Gas (Topic 932). The standardized measure does not purport to
reflect realizable values or fair market value of Eni’s proved reserves.
An estimate of fair value would also take into account, among
other things, hydrocarbon resources other than proved reserves,
anticipated changes in future prices and costs and a discount factor
representative of the risks inherent in the oil and gas exploration and
production activity.
(€ million)
December 31, 2019
Consolidated subsidiaries
Future cash inflows
Future production costs
Future development
and abandonment costs
Future net inflow before income
tax
Future income tax
Future net cash flows
10 % discount factor
Standardized measure of
discounted future net cash flows
Equity-accounted entities
Future cash inflows
Future production costs
Future development and
abandonment costs
Future net inflow before income
tax
Future income tax
Future net cash flows
10 % discount factor
Standardized measure of
discounted future net cash flows
Total consolidated subsidiaries
and equity-accounted entities
Italy
Rest of
Europe
North
Africa
Sub-Saharan
Egypt
Africa Kazakhstan
Rest
of Asia
America
Australia
and Oceania
Total
12,363
(5,078)
3,268
(1,175)
38,083
(6,944)
37,020
(10,934)
48,778
(15,534)
36,435
(8,239)
31,220
(8,888)
11,378
(5,060)
1,686
(293)
220,231
(62,145)
(3,551)
(1,338)
(4,985)
(1,591)
(6,265)
(2,362)
(6,047)
(2,629)
(225)
(28,993)
3,734
(796)
2,938
(466)
755
(249)
506
63
26,154
(13,632)
12,522
(5,852)
24,495
(7,829)
16,666
(5,822)
26,979
(9,926)
17,053
(6,604)
25,834
(5,485)
20,349
(10,832)
16,285
(11,379)
4,906
(1,990)
3,689
(1,034)
2,655
(1,187)
1,168
(143)
1,025
(443)
129,093
(50,473)
78,620
(33,133)
2,472
569
6,670
10,844
10,449
9,517
2,916
1,468
582
45,487
25,094
(6,953)
(6,519)
11,622
(7,020)
4,602
(1,544)
3,058
380
(113)
(23)
244
(77)
167
(88)
79
1,787
(863)
(59)
865
(225)
640
(322)
318
7,730
(2,038)
(145)
5,547
(1,783)
3,764
(1,809)
1,955
34,991
(9,967)
(6,746)
18,278
(9,105)
9,173
(3,763)
5,410
2,472
3,627
6,749
10,844
10,767
9,517
2,916
3,423
582
50,897
CONSOLIDATED FINANCIAL STATEMENTS 2019 | SUPPLEMENTAL OIL AND GAS INFORMATIONEni Annual Report 2019
262
(€ million)
December 31, 2018
Consolidated subsidiaries
Future cash inflows
Future production costs
Future development and abandonment
costs
Future net inflow before income tax
Future income tax
Future net cash flows
10 % discount factor
Standardized measure of discounted
future net cash flows
Equity-accounted entities
Future cash inflows
Future production costs
Future development and abandonment
costs
Future net inflow before income tax
Future income tax
Future net cash flows
10 % discount factor
Standardized measure of discounted
future net cash flows
Total consolidated subsidiaries and
equity-accounted entities
(€ million)
December 31, 2017
Consolidated subsidiaries
Future cash inflows
Future production costs
Future development and abandonment
costs
Future net inflow before income tax
Future income tax
Future net cash flows
10 % discount factor
Standardized measure of discounted
future net cash flows
Equity-accounted entities
Future cash inflows
Future production costs
Future development and abandonment
costs
Future net inflow before income tax
Future income tax
Future net cash flows
10 % discount factor
Standardized measure of discounted
future net cash flows
Total consolidated subsidiaries and
equity-accounted entities
Rest of
Europe
North
Africa
Italy
Sub-Saharan
Egypt
Africa Kazakhstan
Rest
of Asia
America
Australia
and Oceania
Total
18,372
(5,659)
4,895
(1,438)
43,578
(6,653)
39,193
(12,193)
(4,670)
8,043
(1,671)
6,372
(2,045)
(1,350)
2,107
(798)
1,309
(124)
(4,700)
32,225
(17,514)
14,711
(6,727)
(2,769)
24,231
(7,829)
16,402
(6,564)
53,534
(16,417)
(6,778)
30,339
(11,566)
18,773
(7,501)
40,698
(8,276)
33,384
(9,492)
14,192
(6,038)
2,319
(511)
250,165
(66,677)
(2,640)
29,782
(6,524)
23,258
(12,477)
(5,755)
18,137
(11,980)
6,157
(2,258)
(2,467)
5,687
(1,791)
3,896
(1,508)
(291)
1,517
(289)
1,228
(491)
(31,420)
152,068
(59,962)
92,106
(39,695)
4,327
1,185
7,984
9,838
11,272
10,781
3,899
2,388
737
52,411
18,608
(4,686)
(3,633)
10,289
(6,822)
3,467
(1,104)
347
(138)
(3)
206
(43)
163
(76)
2,363
87
2,675
(873)
(75)
1,727
(204)
1,523
(793)
730
8,292
(2,192)
(191)
5,909
(1,839)
4,070
(2,009)
2,061
29,922
(7,889)
(3,902)
18,131
(8,908)
9,223
(3,982)
5,241
4,327
3,548
8,071
9,838
12,002
10,781
3,899
4,449
737
57,652
Rest of
Europe
North
Africa
Italy
Sub-Saharan
Egypt
Africa Kazakhstan
Rest
of Asia
America
Australia and
Oceania
Total
14,339
(5,091)
19,507
(5,711)
31,793
(6,677)
29,156
(6,153)
(3,943)
5,305
(859)
4,446
(1,633)
(5,483)
8,313
(4,490)
3,823
(1,050)
(4,350) (4,496)
18,507
20,766
(5,709)
(10,836)
12,798
9,930
(4,566) (6,698)
41,136
(14,790)
(6,522)
19,824
(6,418)
13,406
(5,430)
30,263
(6,992)
(2,787)
20,484
(3,970)
16,514
(9,172)
11,826
(3,653)
(3,694)
4,479
(757)
3,722
(1,239)
6,205
(2,351)
(1,011)
2,843
(699)
2,144
(777)
2,593
(590)
186,818
(52,008)
(318)
1,685
(303)
1,382
(607)
(32,604)
102,206
(34,041)
68,165
(31,172)
2,813
2,773
5,364
6,100
7,976
7,342
2,483
1,367
775
36,993
245
(119)
(1)
125
(21)
104
(50)
54
2,813
2,773
5,418
6,100
2,062
(930)
(66)
1,066
(57)
1,009
(471)
538
8,514
11
(6)
5
(1)
4
10,797
(3,291)
(535)
6,971
(2,459)
4,512
(2,475)
4
2,037
13,115
(4,346)
(602)
8,167
(2,538)
5,629
(2,996)
2,633
7,342
2,487
3,404
775
39,626
CONSOLIDATED FINANCIAL STATEMENTS 2019 | SUPPLEMENTAL OIL AND GAS INFORMATION
263
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
Changes in standardized measure of discounted future net cash flows for the years ended December 31, 2019, 2018 and 2017, are as follows:
(€ million)
2019
Standardized measure of discounted future net cash flows at December 31, 2018
Increase (Decrease):
- sales, net of production costs
- net changes in sales and transfer prices, net of production costs
- extensions, discoveries and improved recovery, net of future production and development costs
- changes in estimated future development and abandonment costs
- development costs incurred during the period that reduced future development costs
- revisions of quantity estimates
- accretion of discount
- net change in income taxes
- purchase of reserves in-place
- sale of reserves in-place(a)
- changes in production rates (timing) and other
Net increase (decrease)
Standardized measure of discounted future net cash flows at December 31, 2019
Consolidated
subsidiaries
Equity-account-
ed entities
Total
52,411
5,241
57,652
(18,236)
(14,972)
1,240
(1,157)
5,128
5,573
8,666
6,013
260
(429)
990
(6,924)
45,487
(1,675)
(2,247)
86
(916)
687
1,377
1,050
(761)
2,579
(88)
77
169
5,410
(19,911)
(17,219)
1,326
(2,073)
5,815
6,950
9,716
5,252
2,839
(517)
1,067
(6,755)
50,897
(a) Includes volume as part of a long-term supply agreement to a state-owned national oil company, whereby the buyer has paid the price without lifting the underlying volume in
exercise of the take-or-pay clause because it is very likely that the buyer will not redeem its contractual right to lift (make up) the volume paid.
2018
Standardized measure of discounted future net cash flows at December 31, 2017
Increase (Decrease):
- sales, net of production costs
- net changes in sales and transfer prices, net of production costs
- extensions, discoveries and improved recovery, net of future production and development costs
- changes in estimated future development and abandonment costs
- development costs incurred during the period that reduced future development costs
- revisions of quantity estimates
- accretion of discount
- net change in income taxes
- purchase of reserves in-place
- sale of reserves in-place
- changes in production rates (timing) and other
Net increase (decrease)
Standardized measure of discounted future net cash flows at December 31, 2018
2017
Standardized measure of discounted future net cash flows at December 31, 2016
Increase (Decrease):
- sales, net of production costs
- net changes in sales and transfer prices, net of production costs
- extensions, discoveries and improved recovery, net of future production and development costs
- changes in estimated future development and abandonment costs
- development costs incurred during the period that reduced future development costs
- revisions of quantity estimates
- accretion of discount
- net change in income taxes
- purchase of reserves in-place
- sale of reserves in-place
- changes in production rates (timing) and other
Net increase (decrease)
Standardized measure of discounted future net cash flows at December 31, 2017
36,993
2,633
39,626
(19,793)
27,970
1,649
(2,525)
6,468
10,487
5,670
(16,566)
5,369
(8,363)
5,052
15,418
52,411
(445)
671
216
14
(803)
384
193
6,700
(4,322)
2,608
5,241
(20,238)
28,641
1,649
(2,309)
6,482
9,684
6,054
(16,373)
12,069
(8,363)
730
18,026
57,652
26,717
3,121
29,838
(14,125)
23,940
1,697
(2,817)
7,203
5,269
3,864
(6,498)
10
(2,995)
(5,272)
10,276
36,993
(432)
1,482
495
45
(2,285)
438
238
(469)
(488)
2,633
(14,557)
25,422
1,697
(2,322)
7,248
2,984
4,302
(6,260)
10
(2,995)
(5,741)
9,788
39,626
CONSOLIDATED FINANCIAL STATEMENTS 2019 | SUPPLEMENTAL OIL AND GAS INFORMATIONEni Annual Report 2019
264
Certification pursuant to rule 154-bis, paragraph 5 of the
Legislative Decree No. 58/1998 (Testo Unico della Finanza)
1.
•
•
2.
The undersigned Claudio Descalzi and Massimo Mondazzi, in their quality as Chief Executive Officer and Officer responsible for the
preparation of financial reports of Eni, also pursuant to article 154-bis, paragraphs 3 and 4 of Legislative Decree No. 58 of February 24,
1998, certify that internal controls over financial reporting in place for the preparation of the consolidated financial statements as of
December 31, 2019 and during the period covered by the report, were:
adequate to the Company structure, and
effectively applied during the process of preparation of the report.
Internal controls over financial reporting in place for the preparation of the 2019 consolidated financial statements have been defined and
the evaluation of their effectiveness has been assessed based on principles and methodologies adopted by Eni in accordance with the
Internal Control-Integrated Framework Model issued by the Committee of Sponsoring Organizations of the Treadway Commission, which
represents an internationally-accepted framework for the internal control system.
The undersigned officers also certify that:
3.
3.1 2019 consolidated financial statements:
a) have been prepared in accordance with applicable international accounting standards adopted by the European Community
pursuant to Regulation (CE) n. 1606/2002 of the European Parliament and European Council of July 19, 2002;
b) correspond to the accounting books and entries;
c)
fairly and truly represent the financial position, the performance and the cash flows of the issuer and the companies included
in the consolidation as of, and for, the period presented in this report.
3.2 The operating and financial review provides a reliable analysis of business trends and results, including trend analysis of the issuer and the
companies included in the consolidation, as well as a description of the main risks and uncertainties to which they are exposed.
February 27, 2020
/s/ Claudio Descalzi
Claudio Descalzi
Chief Executive Officer
/s/ Massimo Mondazzi
Massimo Mondazzi
Chief Financial Officer and
Officer responsible for the
preparation of financial reports
Report of Independent Auditors
265
266
267
268
269
270
271
272
273
Annex
2019
2 |
M A N A G E M E N T R E P O R T
1 4 3 |
C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S
2 7 5 |
A N N E X
List of companies owned by Eni SpA as of December 31, 2019
Investments owned by Eni as of December 31, 2019
Changes in the scope of consolidation for 2019
276
277
299
276
LIST OF COMPANIES OWNED BY ENI SPA
AS OF DECEMBER 31, 2019
INVESTMENTS OWNED BY ENI
AS OF DECEMBER 31, 2019
In accordance with the provisions of articles 38 and 39 of the
Legislative Decree No. 127/1991 and Consob communication
No. DEM/6064293 of July 28, 2006, the list of subsidiaries, joint
arrangements and associates and significant investments owned
by Eni SpA as of december 31, 2019, is presented below. Companies
are divided by business segment and, within each segment, they
are ordered between Italy and outside Italy and alphabetically.
For each company are indicated: company name, registered head
office, operating office, share capital, shareholders and percentage
of ownership; for consolidated subsidiaries is indicated the equity
Fully consolidated subsidiaries
Consolidated joint operations
Investments owned by consolidated companies(b)
Equity-accounted investments
Investments at cost net of impairment losses
Investments at fair value
Investments owned by unconsolidated com-
panies
Owned by controlled companies
Owned by joint arrangements
Total
Subsidiaries
Italy
29
Outside
Italy
147
3
5
8
1
1
38
33
6
39
1
1
187
Total
176
36
11
47
2
2
225
ratio attributable to Eni; for unconsolidated investments owned by
consolidated companies is indicated the valuation method.
In the footnotes are indicated which investments are quoted in
the Italian regulated markets or in other regulated markets of
the European Union and the percentage of the ordinary voting
rights entitled to shareholders if different from the percentage
of ownership. The currency codes indicated are reported in
accordance with the International Standard ISO 4217.
As of December 31, 2019, the breakdown of the companies owned
by Eni is provided in the table below:
Joint arrangements
and associates
Other significant investments(a)
Italy
Outside
Italy
Total
Italy
Outside
Italy
Total
6
18
2
20
26
5
45
30
75
4
4
84
11
63
32
95
4
4
110
2
2
2
21
21
23
23
21
23
(a) Relates to investments other than subsidiaries, joint arrangements and associates with an ownership interest greater than 2% for listed companies or 10% for unlisted companies.
(b) Investments in subsidiaries accounted for using the equity method and at cost net of impairment losses relate to non-significant companies.
SUBSIDIARIES AND JOINT ARRANGEMENTS
RESIDENT IN STATES OR TERRITORY WITH
A PRIVILEGED TAX REGIME
The Legislative Decree of 29 November 2018, No. 241, enforcing the EU
Directive rules in the matter of tax avoidance practices, modified the
definition of a State or territory with a privileged tax regime pursuant
to art. 47-bis of the D.P.R. December 22, 1986, No. 917. Following the
aforementioned amendments and the amendments to art. 167 of the
D.P.R. December 22, 1986, No. 917, the provisions regarding foreign
subsidiaries, CFC, are applied if the non-resident controlled entities
jointly present the following conditions: (a) they are subject to an
effective taxation of less than half to which they would have been
subject if they were resident in Italy; (b) more than one third of the
proceeds fall into one or more of the following categories: interests,
royalties, dividends, financial leasing income, income from insurance
and banking activities, income from intra-group services with low or
zero added economic value.
As of December 31, 2019, Eni controls 5 companies that benefit from a
privileged tax regime. Of these 5 companies, 4 are subject to taxation
in Italy because they are included in Eni's tax return, 1 company is not
subject to taxation in Italy for the exemption obtained by the Revenue
Agency. No subsidiary that benefits from a privileged tax regime has
issued financial instruments. All the financial statements for 2019 are
audited by PricewaterhouseCoopers.
ANNEX TO FINANCIAL STATEMENTS | INVESTMENTS OWNED BY ENI AS OF DECEMBER 31, 2019
PARENT COMPANY
e
m
a
n
y
n
a
p
m
o
C
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
y
c
n
e
r
r
u
C
l
a
t
i
p
a
C
e
r
a
h
S
s
r
e
d
l
o
h
e
r
a
h
S
Eni SpA(#)
Rome
Italy
EUR
4,005,358,876
Cassa Depositi e Prestiti SpA
Ministero dell'Economia e delle Finanze
Eni SpA
Other shareholders
277
p
i
h
s
r
e
n
w
O
%
25.76
4.34
1.70
68.20
SUBSIDIARIES
Exploration & Production
IN ITALY
e
m
a
n
y
n
a
p
m
o
C
Eni Angola SpA
Eni Mediterranea Idrocarburi SpA
Eni Mozambico SpA
Eni Timor Leste SpA
Eni West Africa SpA
EniProgetti SpA
Floaters SpA
Ieoc SpA
Società Petrolifera Italiana SpA
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
San Donato
Milanese (MI)
Gela (CL)
San Donato
Milanese (MI)
San Donato
Milanese (MI)
San Donato
Milanese (MI)
Venezia
Marghera (VE)
San Donato
Milanese (MI)
San Donato
Milanese (MI)
San Donato
Milanese (MI)
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
y
c
n
e
r
r
u
C
l
a
t
i
p
a
C
e
r
a
h
S
s
r
e
d
l
o
h
e
r
a
h
S
p
i
h
s
r
e
n
w
O
%
o
i
t
a
r
y
t
i
u
q
E
%
)
*
(
d
o
h
t
e
m
n
o
i
t
a
t
u
l
a
v
r
o
n
o
i
t
a
d
i
l
o
s
n
o
C
Angola
EUR
20,200,000
Eni SpA
100.00
100.00
Italy
Mozambique
EUR
EUR
5,200,000
Eni SpA
200,000
Eni SpA
100.00
100.00
100.00
100.00
East Timor
EUR
6,841,517
Eni SpA
100.00
100.00
Angola
EUR
10,000,000
Eni SpA
100.00
100.00
Italy
Italy
EUR
2,064,000
Eni SpA
100.00
100.00
EUR
200,120,000
Eni SpA
100.00
100.00
Egypt
EUR
7,518,000
Eni SpA
100.00
100.00
Italy
EUR
13,877,600
Eni SpA
Third parties
99.96
0.04
99.96
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.
(#) Company with shares quoted in the regulated market of Italy or of other EU Countries.
ANNEX TO FINANCIAL STATEMENTS | SUBSIDIARESEni Annual Report 2019
278
OUTSIDE ITALY
e
m
a
n
y
n
a
p
m
o
C
Agip Caspian Sea BV
Agip Energy and Natural
Resources (Nigeria) Ltd
Agip Karachaganak BV
Agip Oleoducto de Crudos
Pesados BV (in liquidation)
Burren Energy (Bermuda) Ltd(1)
Burren Energy (Egypt) Ltd
Burren Energy Congo Ltd
Burren Energy India Ltd
Burren Energy Plc
Burren Shakti Ltd(2)
Eni Abu Dhabi BV
Eni AEP Ltd
Eni Albania BV
Eni Algeria Exploration BV
Eni Algeria Ltd Sàrl
Eni Algeria Production BV
Eni Ambalat Ltd
Eni America Ltd
Eni Angola Exploration BV
Eni Angola Production BV
Eni Argentina Exploración
y Explotación SA
Eni Arguni I Ltd
Eni Australia BV
Eni Australia Ltd
Eni Bahrain BV
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
Amsterdam
(Netherlands)
Abuja
(Nigeria)
Amsterdam
(Netherlands)
Amsterdam
(Netherlands)
Hamilton
(Bermuda)
London
(United Kingdom)
Tortola
(British Virgin
Islands)
London
(United Kingdom)
London
(United Kingdom)
Hamilton
(Bermuda)
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
y
c
n
e
r
r
u
C
l
a
t
i
p
a
C
e
r
a
h
S
s
r
e
d
l
o
h
e
r
a
h
S
p
i
h
s
r
e
n
w
O
%
o
i
t
a
r
y
t
i
u
q
E
%
Kazakhstan
EUR
20,005
Eni International BV
100.00
100.00
Nigeria
NGN
5,000,000
Eni International BV
Eni Oil Holdings BV
95.00
5.00
100.00
Kazakhstan
EUR
20,005
Eni International BV
100.00
100.00
Ecuador
United
Kingdom
Egypt
Republic
of the Congo
EUR
USD
GBP
USD
20,000
Eni International BV
100.00
12,002
Burren Energy Plc
100.00
100.00
2
Burren Energy Plc
100.00
50,000
Burren En. (Berm) Ltd
100.00
100.00
United Kingdom GBP
2
Burren Energy Plc
100.00
100.00
United Kingdom GBP
28,819,023
Eni UK Holding Plc
Eni UK Ltd
99.99
(..)
100.00
United Kingdom USD
213,138
Burren En. India Ltd
100.00
100.00
Amsterdam
(Netherlands)
United Arab
Emirates
EUR
20,000
Eni International BV
100.00
100.00
Pakistan
GBP
13,471,000
Eni UK Ltd
100.00
100.00
Netherlands
EUR
20,000
Eni International BV
100.00
Algeria
Algeria
Algeria
Angola
Angola
EUR
USD
EUR
GBP
USD
EUR
EUR
20,000
Eni International BV
100.00
100.00
20,000
Eni Oil Holdings BV
100.00
100.00
20,000
Eni International BV
100.00
100.00
1
Eni Indonesia Ltd
100.00
100.00
72,000
Eni UHL Ltd
100.00
100.00
20,000
Eni International BV
100.00
100.00
20,000
Eni International BV
100.00
100.00
London
(United Kingdom)
Indonesia
Dover, Delaware
(USA)
USA
Argentina
ARS
24,136,336
Eni International BV
Eni Oil Holdings BV
95.00
5.00
100.00
London
(United Kingdom)
Indonesia
Australia
GBP
EUR
1
Eni Indonesia Ltd
100.00
100.00
20,000
Eni International BV
100.00
100.00
London
(United Kingdom)
Amsterdam
(Netherlands)
Amsterdam
(Netherlands)
Luxembourg
(Luxembourg)
Amsterdam
(Netherlands)
Amsterdam
(Netherlands)
Amsterdam
(Netherlands)
Buenos Aires
(Argentina)
Amsterdam
(Netherlands)
London
(United Kingdom)
Amsterdam
(Netherlands)
Australia
GBP
20,000,000
Eni International BV
100.00
100.00
Bahrain
EUR
20,000
Eni International BV
100.00
100.00
)
*
(
d
o
h
t
e
m
n
o
i
t
a
t
u
l
a
v
r
o
n
o
i
t
a
d
i
l
o
s
n
o
C
F.C.
F.C.
F.C.
Co.
F.C.
Eq.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
Eq.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.
(1) Company that benefits from a privileged tax regime pursuant to art. 167, paragraph 4 of the D.P.R. of December 22, 1986, n. 917: the company is not subjected to taxation in Italy for the exemption
obtained by the Revenue Agency.
(2) Company that benefits from a privileged tax regime pursuant to art. 167, paragraph 4 of the D.P.R. of December 22, 1986, n. 917: the company is subjected to taxation in Italy because it is included in
Eni's tax return.
ANNEX TO FINANCIAL STATEMENTS | SUBSIDIARES
e
m
a
n
y
n
a
p
m
o
C
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
Eni BB Petroleum Inc
Dover, Delaware
(USA)
USA
y
c
n
e
r
r
u
C
USD
l
a
t
i
p
a
C
e
r
a
h
S
s
r
e
d
l
o
h
e
r
a
h
S
p
i
h
s
r
e
n
w
O
%
o
i
t
a
r
y
t
i
u
q
E
%
1,000
Eni Petroleum Co Inc
100.00
100.00
1
1
Eni International BV
100.00
Eni Indonesia Ltd
100.00
100.00
20,000
Eni International BV
100.00
United Kingdom GBP
Indonesia
Indonesia
GBP
EUR
Canada
USD
1,453,200,001
Eni International BV
100.00
100.00
Indonesia
USD
2,210,728
Eni Lasmo Plc
100.00
100.00
China
EUR
20,000
Eni International BV
100.00
100.00
Republic
of the Congo
USD
17,000,000
Ivory Coast
GBP
1
Eni E&P Holding BV
Eni Int. NA NV Sàrl
Eni International BV
Eni Lasmo Plc
99.99
(..)
(..)
100.00
100.00
100.00
Cyprus
Greenland
EUR
EUR
2,006
Eni International BV
100.00
100.00
20,000
Eni International BV
100.00
Brazil
BRL
1,593,415,000
Eni International BV
Eni Oil Holdings BV
99.99
(..)
Indonesia
Indonesia
GBP
GBP
1
1
Eni Indonesia Ltd
100.00
100.00
Eni Indonesia Ltd
100.00
100.00
United Kingdom GBP
100
Eni UK Ltd
100.00
100.00
Netherlands
EUR
20,000
Eni International BV
100.00
100.00
Netherlands
EUR
29,832,777.12
Eni International BV
100.00
100.00
Gabon
XAF 13,132,000,000
Eni International BV
100.00
100.00
Indonesia
GBP
2
Eni Indonesia Ltd
100.00
100.00
Australia
EUR
10,000,000
Eni International BV
100.00
100.00
Ghana
GHS
21,412,500
Eni International BV
100.00
100.00
United Kingdom GBP
3,036,000
Eni UK Ltd
100.00
100.00
Venezuela
GBP
8,050,500
Eni Lasmo Plc
100.00
100.00
London
(United Kingdom)
London
(United Kingdom)
Amsterdam
(Netherlands)
Calgary
(Canada)
London
(United Kingdom)
Amsterdam
(Netherlands)
Pointe - Noire
(Republic of the
Congo)
London
(United Kingdom)
Nicosia
(Cyprus)
Amsterdam
(Netherlands)
Rio de Janeiro
(Brazil)
London
(United Kingdom)
London
(United Kingdom)
London
(United Kingdom)
Amsterdam
(Netherlands)
Amsterdam
(Netherlands)
Libreville
(Gabon)
London
(United Kingdom)
Amsterdam
(Netherlands)
Accra
(Ghana)
Aberdeen
(United Kingdom)
London
(United Kingdom)
London
(United Kingdom)
India
GBP
44,000,000
Eni Lasmo Plc
100.00
London
(United Kingdom)
Indonesia
GBP
100
Eni ULX Ltd
100.00
100.00
Eni BTC Ltd
Eni Bukat Ltd
Eni Bulungan BV
(in liquidation)
Eni Canada Holding Ltd
Eni CBM Ltd
Eni China BV
Eni Congo SA
Eni Côte d’Ivoire Ltd
Eni Cyprus Ltd
Eni Denmark BV
Eni do Brasil Investimentos
em Exploração e Produção
de Petróleo Ltda
Eni East Ganal Ltd
Eni East Sepinggan Ltd
Eni Elgin/Franklin Ltd
Eni Energy Russia BV
Eni Exploration
& Production Holding BV
Eni Gabon SA
Eni Ganal Ltd
Eni Gas & Power LNG Australia BV
Eni Ghana Exploration
and Production Ltd
Eni Hewett Ltd
Eni Hydrocarbons Venezuela Ltd
Eni India Ltd
Eni Indonesia Ltd
(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.
279
)
*
(
d
o
h
t
e
m
n
o
i
t
a
t
u
l
a
v
r
o
n
o
i
t
a
d
i
l
o
s
n
o
C
F.C.
Eq.
F.C.
Co.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
Eq.
Eq.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
Eq.
F.C.
ANNEX TO FINANCIAL STATEMENTS | SUBSIDIARESEni Annual Report 2019
280
e
m
a
n
y
n
a
p
m
o
C
Eni Indonesia Ots 1 Ltd
Eni International NA NV Sàrl
Eni Investments Plc
Eni Iran BV
Eni Iraq BV
Eni Ireland BV
Eni Isatay BV
Eni JPDA 03-13 Ltd
Eni JPDA 06-105 Pty Ltd
Eni JPDA 11-106 BV
Eni Kenya BV
Eni Krueng Mane Ltd
Eni Lasmo Plc
Eni Lebanon BV
Eni Liberia BV
Eni Liverpool Bay Operating Co Ltd
Eni LNS Ltd
Eni Marketing Inc
Eni Maroc BV
Eni México S. de RL de CV
Eni Middle East Ltd
Eni MOG Ltd
(in liquidation)
Eni Montenegro BV
Eni Mozambique Engineering Ltd
Eni Mozambique LNG Holding BV
Eni Muara Bakau BV
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
Grand Cayman
(Cayman Islands)
Luxembourg
(Luxembourg)
London
(United Kingdom)
Amsterdam
(Netherlands)
Amsterdam
(Netherlands)
Amsterdam
(Netherlands)
Amsterdam
(Netherlands)
London
(United Kingdom)
Perth
(Australia)
Amsterdam
(Netherlands)
Amsterdam
(Netherlands)
London
(United Kingdom)
London
(United Kingdom)
Amsterdam
(Netherlands)
Amsterdam
(Netherlands)
London
(United Kingdom)
London
(United Kingdom)
Amsterdam
(Netherlands)
Lomas
De Chapultepec,
Mexico City
(Mexico)
London
(United Kingdom)
London
(United Kingdom)
Amsterdam
(Netherlands)
London
(United Kingdom)
Amsterdam
(Netherlands)
Amsterdam
(Netherlands)
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
y
c
n
e
r
r
u
C
l
a
t
i
p
a
C
e
r
a
h
S
s
r
e
d
l
o
h
e
r
a
h
S
p
i
h
s
r
e
n
w
O
%
o
i
t
a
r
y
t
i
u
q
E
%
Indonesia
USD
1,01
Eni Indonesia Ltd
100.00
100.00
United Kingdom USD
25,000
Eni International BV
100.00
100.00
United Kingdom GBP
750,050,000
Eni SpA
Eni UK Ltd
20,000
Eni International BV
100.00
99.99
(..)
100.00
Iran
Iraq
Ireland
EUR
EUR
EUR
20,000
Eni International BV
100.00
100.00
20,000
Eni International BV
100.00
100.00
Kazakhstan
EUR
20,000
Eni International BV
100.00
100.00
Australia
GBP
250,000
Eni International BV
100.00
100.00
Australia
AUD
80,830,576
Eni International BV
100.00
100.00
Australia
Kenya
Indonesia
EUR
EUR
GBP
50,000
Eni International BV
100.00
100.00
20,000
Eni International BV
100.00
100.00
2
Eni Indonesia Ltd
100.00
100.00
United Kingdom GBP 337,638,724.25
Eni Investments Plc
Eni UK Ltd
99.99
(..)
100.00
Lebanon
Liberia
EUR
EUR
20,000
Eni International BV
100.00
100.00
20,000
Eni International BV
100.00
United Kingdom GBP
1
Eni UK Ltd
100.00
United Kingdom GBP
80,400,000
Eni UK Ltd
100.00
100.00
Dover, Delaware
(USA)
USA
Morocco
Mexico
USD
EUR
MXN
1,000
Eni Petroleum Co Inc
100.00
100.00
20,000
Eni International BV
100.00
100.00
3,000
Eni International BV
Eni Oil Holdings BV
99.90
0.10
100.00
United Kingdom GBP
1
Eni ULT Ltd
100.00
100.00
United Kingdom GBP 220,711,147.50
Eni Lasmo Plc
Eni LNS Ltd
99.99
(..)
100.00
Montenegro
EUR
20,000
Eni International BV
100.00
100.00
United Kingdom GBP
1
Eni Lasmo Plc
100.00
100.00
Netherlands
EUR
20,000
Eni International BV
100.00
100.00
Indonesia
EUR
20,000
Eni International BV
100.00
100.00
(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.
)
*
(
d
o
h
t
e
m
n
o
i
t
a
t
u
l
a
v
r
o
n
o
i
t
a
d
i
l
o
s
n
o
C
F.C.
F.C.
F.C.
Eq.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
Eq.
Eq.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
ANNEX TO FINANCIAL STATEMENTS | SUBSIDIARES
e
m
a
n
y
n
a
p
m
o
C
Eni Myanmar BV
Eni North Africa BV
Eni North Ganal Ltd
Eni Oil & Gas Inc
Eni Oil Algeria Ltd
Eni Oil Holdings BV
Eni Oman BV
Eni Pakistan Ltd
Eni Pakistan (M) Ltd Sàrl
Eni Petroleum Co Inc
Eni Petroleum US Llc
Eni Portugal BV
Eni RAK BV
Eni Rapak Ltd
Eni RD Congo SA
Eni Rovuma Basin BV
Eni Sharjah BV
Eni South Africa BV
Eni South China Sea Ltd Sàrl
Eni TNS Ltd
Eni Tunisia BV
Eni Turkmenistan Ltd
Eni UHL Ltd
Eni UK Holding Plc
Eni UK Ltd
Eni UKCS Ltd
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
Amsterdam
(Netherlands)
Amsterdam
(Netherlands)
Myanmar
Libya
London
(United Kingdom)
Indonesia
Dover, Delaware
(USA)
USA
London
(United Kingdom)
Algeria
y
c
n
e
r
r
u
C
EUR
EUR
GBP
USD
GBP
l
a
t
i
p
a
C
e
r
a
h
S
s
r
e
d
l
o
h
e
r
a
h
S
p
i
h
s
r
e
n
w
O
%
o
i
t
a
r
y
t
i
u
q
E
%
20,000
Eni International BV
100.00
100.00
20,000
Eni International BV
100.00
100.00
1
Eni Indonesia Ltd
100.00
100.00
100,800
Eni America Ltd
100.00
100.00
1,000
Eni Lasmo Plc
100.00
100.00
Netherlands
EUR
450,000
Eni ULX Ltd
100.00
100.00
London
(United Kingdom)
Pakistan
Amsterdam
(Netherlands)
Amsterdam
(Netherlands)
Luxembourg
(Luxembourg)
Dover, Delaware
(USA)
Dover, Delaware
(USA)
Amsterdam
(Netherlands)
Amsterdam
(Netherlands)
London
(United Kingdom)
Kinshasa
(Democratic
Republic
of the Congo )
Amsterdam
(Netherlands)
Amsterdam
(Netherlands)
Amsterdam
(Netherlands)
Luxembourg
(Luxembourg)
Aberdeen
(United Kingdom)
Amsterdam
(Netherlands)
Hamilton
(Bermuda)
London
(United Kingdom)
London
(United Kingdom)
London
(United Kingdom)
London
(United Kingdom)
Oman
Pakistan
USA
USA
Portugal
EUR
GBP
USD
20,000
Eni International BV
100.00
100.00
90,087
Eni ULX Ltd
100.00
100.00
20,000
Eni Oil Holdings BV
100.00
100.00
USD
156,600,000
Eni SpA
Eni International BV
63.86
36.14
100.00
USD
EUR
1,000
Eni BB Petroleum Inc
100.00
100.00
20,000
Eni International BV
100.00
Netherlands
EUR
20,000
Eni International BV
100.00
100.00
Indonesia
GBP
2
Eni Indonesia Ltd
100.00
100.00
Democratic
Republic
of the Congo
CDF
750,000,000
Eni International BV
Eni Oil Holdings BV
99.99
(..)
Mozambique
EUR
20,000
Eni Mozambique LNG H. BV 100.00
100.00
United Arab
Emirates
Republic of
South Africa
China
EUR
EUR
USD
20,000
Eni International BV
100.00
100.00
20,000
Eni International BV
100.00
100.00
20,000
Eni International BV
100.00
United Kingdom GBP
1,000
Eni UK Ltd
100.00
100.00
Tunisia
EUR
20,000
Eni International BV
100.00
100.00
Turkmenistan
USD
20,000
Burren En. (Berm) Ltd
100.00
100.00
United Kingdom GBP
1
Eni ULT Ltd
100.00
100.00
United Kingdom GBP
424,050,000
Eni Lasmo Plc
Eni UK Ltd
99.99
(..)
100.00
United Kingdom GBP
250,000,000
Eni International BV
100.00
100.00
United Kingdom GBP
100
Eni UK Ltd
100.00
100.00
(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.
281
)
*
(
d
o
h
t
e
m
n
o
i
t
a
t
u
l
a
v
r
o
n
o
i
t
a
d
i
l
o
s
n
o
C
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
Eq.
F.C.
F.C.
Eq.
F.C.
F.C.
F.C.
Eq.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
ANNEX TO FINANCIAL STATEMENTS | SUBSIDIARESEni Annual Report 2019
282
e
m
a
n
y
n
a
p
m
o
C
Eni Ukraine Holdings BV
Eni Ukraine Llc
Eni Ukraine Shallow Waters BV
Eni ULT Ltd
Eni ULX Ltd
Eni US Operating Co Inc
Eni USA Gas Marketing Llc
Eni USA Inc
Eni Venezuela BV
Eni Venezuela E&P Holding SA
Eni Ventures Plc
(in liquidation)
Eni Vietnam BV
Eni West Ganal Ltd
Eni West Timor Ltd
Eni Yemen Ltd
EniProgetti Egypt Ltd
Eurl Eni Algérie
First Calgary Petroleums LP
First Calgary Petroleums
Partner Co ULC
Ieoc Exploration BV
Ieoc Production BV
Lasmo Sanga Sanga Ltd
Liverpool Bay Ltd
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
y
c
n
e
r
r
u
C
l
a
t
i
p
a
C
e
r
a
h
S
s
r
e
d
l
o
h
e
r
a
h
S
p
i
h
s
r
e
n
w
O
%
o
i
t
a
r
y
t
i
u
q
E
%
Amsterdam
(Netherlands)
Kiev
(Ukraine)
Amsterdam
(Netherlands)
London
(United Kingdom)
London
(United Kingdom)
Dover, Delaware
(USA)
Dover, Delaware
(USA)
Dover, Delaware
(USA)
Amsterdam
(Netherlands)
Bruxelles
(Belgium)
London
(United Kingdom)
Amsterdam
(Netherlands)
London
(United Kingdom)
London
(United Kingdom)
London
(United Kingdom)
Cairo
(Egypt)
Algiers
(Algeria)
Wilmington
(USA)
Calgary
(Canada)
Amsterdam
(Netherlands)
Amsterdam
(Netherlands)
Hamilton
(Bermuda)
London
(United Kingdom)
Netherlands
EUR
20,000
Eni International BV
100.00
100.00
Ukraine
UAH 42,004,757.64
Eni Ukraine Hold. BV
Eni International BV
Ukraine
EUR
20,000
Eni Ukraine Hold. BV
99.99
0.01
100.00
United Kingdom GBP 93,215,492.25
Eni Lasmo Plc
100.00
100.00
United Kingdom GBP
200,010,000
Eni ULT Ltd
100.00
100.00
USA
USA
USA
Venezuela
USD
USD
USD
EUR
1,000
Eni Petroleum Co Inc
100.00
100.00
10,000
Eni Marketing Inc
100.00
100.00
1,000
Eni Oil & Gas Inc
100.00
100.00
20,000
Eni Venezuela E&P H.
100.00
100.00
Belgium
USD
254,443,200
United Kingdom GBP
278,050,000
Eni International BV
Eni Oil Holdings BV
Eni International BV
Eni Oil Holdings BV
100.00
99.99
(..)
99.99
(..)
Vietnam
Indonesia
Indonesia
EUR
GBP
GBP
20,000
Eni International BV
100.00
100.00
1
1
Eni Indonesia Ltd
100.00
100.00
Eni Indonesia Ltd
100.00
100.00
United Kingdom GBP
1,000
Burren Energy Plc
100.00
Egypt
EGP
50,000
EniProgetti SpA
Eni SpA
Algeria
DZD
1,000,000
Eni Algeria Ltd Sàrl
99.00
1.00
100.00
Algeria
Canada
Egypt
Egypt
Indonesia
USD
CAD
EUR
EUR
USD
1
Eni Canada Hold. Ltd
FCP Partner Co ULC
99.99
0.01
100.00
10
Eni Canada Hold. Ltd
100.00
100.00
20,000
Eni International BV
100.00
100.00
20,000
Eni International BV
100.00
100.00
12,000
Eni Lasmo Plc
100.00
100.00
United Kingdom USD
1
Eni ULX Ltd
100.00
Mizamtec Operating Company
S. de RL de CV
Mexico City
(Mexico)
Mexico
MXN
3,000
Nigerian Agip CPFA Ltd
Nigerian Agip Exploration Ltd
Lagos
(Nigeria)
Abuja
(Nigeria)
Nigeria
NGN
1,262,500
Nigeria
NGN
5,000,000
Eni US Op. Co Inc
Eni Petroleum Co Inc
NAOC Ltd
Agip En Nat Res. Ltd
Nigerian Agip E. Ltd
Eni International BV
Eni Oil Holdings BV
99.90
0.10
98.02
0.99
0.99
99.99
0.01
100.00
(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.
)
*
(
d
o
h
t
e
m
n
o
i
t
a
t
u
l
a
v
r
o
n
o
i
t
a
d
i
l
o
s
n
o
C
F.C.
Eq.
Eq.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
Co.
F.C.
F.C.
F.C.
Eq.
Eq.
Eq.
F.C.
F.C.
F.C.
F.C.
F.C.
Eq.
Eq.
Co.
F.C.
ANNEX TO FINANCIAL STATEMENTS | SUBSIDIARES
283
e
m
a
n
y
n
a
p
m
o
C
Nigerian Agip Oil Co Ltd
OOO “Eni Energhia”
Zetah Congo Ltd(2)
Zetah Kouilou Ltd(2)
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
Abuja
(Nigeria)
Moscow
(Russia)
Nassau
(Bahamas)
Nassau
(Bahamas)
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
y
c
n
e
r
r
u
C
l
a
t
i
p
a
C
e
r
a
h
S
s
r
e
d
l
o
h
e
r
a
h
S
Nigeria
NGN
1,800,000
Russia
RUB
2,000,000
Eni International BV
Eni Oil Holdings BV
Eni Energy Russia BV
Eni Oil Holdings BV
Republic
of the Congo
Republic
of the Congo
USD
USD
300
Eni Congo SA
Burren En. Congo Ltd
2,000
Eni Congo SA
Burren En. Congo Ltd
Third parties
o
i
t
a
r
y
t
i
u
q
E
%
100.00
100.00
p
i
h
s
r
e
n
w
O
%
99.89
0.11
99.90
0.10
66.67
33.33
54.50
37.00
8.50
)
*
(
d
o
h
t
e
m
n
o
i
t
a
t
u
l
a
v
r
o
n
o
i
t
a
d
i
l
o
s
n
o
C
F.C.
F.C.
Co.
Co.
(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.
(2) Company that benefits from a privileged tax regime pursuant to art. 167, paragraph 4 of the D.P.R. of December 22, 1986, n. 917: the company is subjected to taxation in Italy because it is included
in Eni's tax return.
ANNEX TO FINANCIAL STATEMENTS | SUBSIDIARESEni Annual Report 2019
284
Gas & Power
IN ITALY
e
m
a
n
y
n
a
p
m
o
C
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
Eni gas e luce SpA
Eni Gas Transport Services Srl
San Donato
Milanese (MI)
San Donato
Milanese (MI)
Eni Trading & Shipping SpA
Rome
EniPower Mantova SpA
EniPower SpA
LNG Shipping SpA
San Donato
Milanese (MI)
San Donato
Milanese (MI)
San Donato
Milanese (MI)
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
Italy
Italy
Italy
Italy
Italy
Italy
y
c
n
e
r
r
u
C
l
a
t
i
p
a
C
e
r
a
h
S
s
r
e
d
l
o
h
e
r
a
h
S
p
i
h
s
r
e
n
w
O
%
o
i
t
a
r
y
t
i
u
q
E
%
EUR
750,000,000
Eni SpA
100.00
100.00
EUR
120,000
Eni SpA
100.00
EUR
60,036,650
Eni SpA
100.00
100.00
EUR
144,000,000
EniPower SpA
Third parties
EUR
944,947,849
Eni SpA
86.50
13.50
86.50
100.00
100.00
EUR
240,900,000
Eni SpA
100.00
100.00
SEA SpA
L'Aquila (AQ)
Italy
EUR
100,000
Eni gas e luce SpA
Third parties
Trans Tunisian Pipeline Co SpA
San Donato
Milanese (MI)
Tunisia
EUR
1,098,000
Eni SpA
60.00
40.00
60.00
100.00
100.00
OUTSIDE ITALY
e
m
a
n
y
n
a
p
m
o
C
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
y
c
n
e
r
r
u
C
l
a
t
i
p
a
C
e
r
a
h
S
s
r
e
d
l
o
h
e
r
a
h
S
p
i
h
s
r
e
n
w
O
%
o
i
t
a
r
y
t
i
u
q
E
%
Adriaplin Podjetje za distribucijo
zemeljskega plina doo Ljubljana
Ljubljana
(Slovenia)
Slovenia
EUR
12,956,935
Eni gas e luce SpA
Third parties
51.00
49.00
51.00
Turkey
EUR
70,000
Eni International BV
100.00
100.00
Eni G&P Trading BV
Eni Gas & Power France SA
Eni Trading & Shipping Inc
Amsterdam
(Netherlands)
Levallois Perret
(France)
France
EUR
29,937,600
Eni gas e luce SpA
Third parties
Dover, Delaware
(USA)
USA
USD
36,000,000
ETS SpA
99.87
0.13
99.87
100.00
100.00
Eni Transporte y Suministro México,
S. de RL de CV
Mexico City
(Mexico)
Gas Supply Company
Thessaloniki - Thessalia SA
Thessaloniki
(Greece)
Société de Service du Gazoduc
Transtunisien SA - Sergaz SA
Société pour la Construction du
Gazoduc Transtunisien SA - Scogat SA
Tunisi
(Tunisia)
Tunisi
(Tunisia)
Mexico
MXN
3,000
Eni International BV
Eni Oil Holdings BV
99.90
0.10
Greece
EUR
13,761,788
Eni gas e luce SpA
100.00
100.00
Tunisia
Tunisia
TND
TND
99,000
Eni International BV
Third parties
200,000
Eni International BV
Eni SpA
LNG Shipping SpA
Trans Tunis. P. Co SpA
66.67
100.00
66.67
33.33
99.85
0.05
0.05
0.05
(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.
)
*
(
d
o
h
t
e
m
n
o
i
t
a
t
u
l
a
v
r
o
n
o
i
t
a
d
i
l
o
s
n
o
C
F.C.
Co.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
)
*
(
d
o
h
t
e
m
n
o
i
t
a
t
u
l
a
v
r
o
n
o
i
t
a
d
i
l
o
s
n
o
C
F.C.
F.C.
F.C.
F.C.
Eq.
F.C.
F.C.
F.C.
ANNEX TO FINANCIAL STATEMENTS | SUBSIDIARES
Refining & Marketing and Chemicals
Refining & Marketing
285
IN ITALY
e
m
a
n
y
n
a
p
m
o
C
Ecofuel SpA
Eni Fuel SpA
Petroven Srl
Raffineria di Gela SpA
SeaPad SpA
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
San Donato
Milanese (MI)
Rome
Genova
Gela (CL)
Genova
Servizi Fondo Bombole Metano SpA
Rome
OUTSIDE ITALY
e
m
a
n
y
n
a
p
m
o
C
Eni Abu Dhabi Refining & Trading BV
Eni Abu Dhabi Refining & Trading
Services BV
Eni Austria GmbH
Eni Benelux BV
Eni Deutschland GmbH
Eni Ecuador SA
Eni France Sàrl
Eni Iberia SLU
Eni Lubricants Trading
(Shangai) Co Ltd
Eni Marketing Austria GmbH
Eni Mineralölhandel GmbH
Eni Schmiertechnik GmbH
Eni Suisse SA
Eni USA R&M Co Inc
Esacontrol SA
Esain SA
Oléoduc du Rhône SA
OOO “Eni-Nefto”
Tecnoesa SA
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
Amsterdam
(Netherlands)
Amsterdam
(Netherlands)
Wien
(Austria)
Rotterdam
(Netherlands)
Munich
(Germany)
Quito
(Ecuador)
Lyon
(France)
Alcobendas
(Spain)
Shanghai
(China)
Wien
(Austria)
Wien
(Austria)
Wurzburg
(Germany)
Lausanne
(Switzerland)
Wilmington
(USA)
Quito
(Ecuador)
Quito
(Ecuador)
Valais
(Switzerland)
Moscow
(Russia)
Quito
(Ecuador)
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
Italy
Italy
Italy
Italy
Italy
Italy
f
o
y
r
t
n
u
o
C
n
o
i
t
a
r
e
p
o
y
c
n
e
r
r
u
C
l
a
t
i
p
a
C
e
r
a
h
S
s
r
e
d
l
o
h
e
r
a
h
S
p
i
h
s
r
e
n
w
O
%
o
i
t
a
r
y
t
i
u
q
E
%
EUR
52,000,000
Eni SpA
100.00
100.00
EUR
EUR
EUR
EUR
58,944,310
Eni SpA
918,520
Ecofuel SpA
15,000,000
Eni SpA
12,400,000
Ecofuel SpA
Third parties
Eni SpA
EUR 13,580,000.20
y
c
n
e
r
r
u
C
l
a
t
i
p
a
C
e
r
a
h
S
s
r
e
d
l
o
h
e
r
a
h
S
100.00
100.00
100.00
100.00
100.00
100.00
80.00
20.00
100.00
p
i
h
s
r
e
n
w
O
%
o
i
t
a
r
y
t
i
u
q
E
%
)
*
(
d
o
h
t
e
m
n
o
i
t
a
t
u
l
a
v
r
o
n
o
i
t
a
d
i
l
o
s
n
o
C
F.C.
F.C.
F.C.
F.C.
Eq.
Co.
)
*
(
d
o
h
t
e
m
n
o
i
t
a
t
u
l
a
v
r
o
n
o
i
t
a
d
i
l
o
s
n
o
C
Netherlands
EUR
20,000
Eni International BV
100.00
100.00
Netherlands
EUR
20,000
Eni Abu Dhabi R&T BV
100.00
Austria
EUR
78,500,000
Netherlands
EUR
1,934,040
Germany
EUR
90,000,000
Ecuador
USD
103,142.08
France
EUR
56,800,000
Eni International BV
Eni Deutsch. GmbH
Eni International BV
Eni International BV
Eni Oil Holdings BV
Eni International BV
Esain SA
Eni International BV
75.00
25.00
100.00
89.00
11.00
99.93
0.07
100.00
100.00
100.00
100.00
100.00
100.00
Spain
China
Austria
Austria
EUR
EUR
17,299,100
Eni International BV
100.00
100.00
5,000,000
Eni International BV
100.00
100.00
EUR 19,621,665.23
EUR 34,156,232.06
Eni Mineralölh. GmbH
Eni International BV
Eni Austria GmbH
99.99
(..)
100.00
100.00
100.00
Germany
EUR
2,000,000
Eni Deutsch. GmbH
100.00
100.00
Switzerland
CHF
102,500,000
Eni International BV
100.00
100.00
USA
USD
11,000,000
Eni International BV
100.00
Ecuador
Ecuador
USD
USD
60,000
30,000
Switzerland
CHF
7,000,000
Russia
Ecuador
RUB
USD
1,010,000
36,000
Eni Ecuador SA
Third parties
Eni Ecuador SA
Tecnoesa SA
Eni International BV
Eni International BV
Eni Oil Holdings BV
Eni Ecuador SA
Esain SA
87.00
13.00
99.99
(..)
100.00
99.01
0.99
99.99
(..)
100.00
F.C.
Eq.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
Eq.
Eq.
F.C.
Eq.
Eq.
Eq.
(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.
ANNEX TO FINANCIAL STATEMENTS | SUBSIDIARESEni Annual Report 2019
286
Chemical
IN ITALY
e
m
a
n
y
n
a
p
m
o
C
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
y
c
n
e
r
r
u
C
l
a
t
i
p
a
C
e
r
a
h
S
s
r
e
d
l
o
h
e
r
a
h
S
p
i
h
s
r
e
n
w
O
%
o
i
t
a
r
y
t
i
u
q
E
%
)
*
(
d
o
h
t
e
m
n
o
i
t
a
t
u
l
a
v
r
o
n
o
i
t
a
d
i
l
o
s
n
o
C
Versalis SpA
San Donato
Milanese (MI)
Italy
EUR 1,364,790,000
Eni SpA
100.00
100.00
F.C.
OUTSIDE ITALY
e
m
a
n
y
n
a
p
m
o
C
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
y
c
n
e
r
r
u
C
l
a
t
i
p
a
C
e
r
a
h
S
s
r
e
d
l
o
h
e
r
a
h
S
p
i
h
s
r
e
n
w
O
%
o
i
t
a
r
y
t
i
u
q
E
%
Dunastyr Polisztirolgyártó Zártkörûen
Mûködõ Részvénytársaság
Budapest
(Hungary)
Hungary
HUF 8,092,160,000
Versalis Americas Inc
Versalis Congo Sarlu
Versalis Deutschland GmbH
Versalis France SAS
Versalis International SA
Versalis Kimya Ticaret Limited Sirketi
Versalis México S. de R.L. de CV
Versalis Pacific (India) Private Ltd
Versalis Pacific Trading
(Shanghai) Co Ltd
Versalis Singapore Pte Ltd
Versalis UK Ltd
Dover, Delaware
(USA)
Pointe-Noire
(Republic
of the Congo)
Eschborn
(Germany)
Mardyck
(France)
Bruxelles
(Belgium)
Istanbul
(Turkey)
Mexico City
(Mexico)
Mumbai
(India)
Shanghai
(China)
Singapore
(Singapore)
London
(United Kingdom)
Versalis SpA
Versalis Deutschland GmbH
Versalis International SA
Versalis International SA
96.34
1.83
1.83
100.00
100.00
100.00
100,000
1,000,000
Versalis International SA
100.00
100.00
USA
Republic
of the Congo
USD
XAF
Germany
EUR
100,000
Versalis SpA
100.00
100.00
France
EUR 126,115,582.90
Versalis SpA
100.00
100.00
Belgium
EUR 15,449,173.88
Versalis SpA
Versalis Deutschland GmbH
Dunastyr Zrt
Versalis France
Versalis International SA
Versalis International SA
Versalis SpA
Versalis Singapore P. Ltd
Third parties
Versalis SpA
59.00
23.71
14.43
2.86
100.00
99.00
1.00
99.99
(..)
100.00
100.00
100.00
20,000
1,000
238,700
1,000,000
80,000
Versalis SpA
100.00
100.00
Turkey
Mexico
India
China
Singapore
TRY
MXN
INR
CNY
SGD
United Kingdom GBP
4,004,042
Versalis SpA
100.00
100.00
)
*
(
d
o
h
t
e
m
n
o
i
t
a
t
u
l
a
v
r
o
n
o
i
t
a
d
i
l
o
s
n
o
C
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
Eq.
Eq.
Eq.
F.C.
F.C.
F.C.
(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.
ANNEX TO FINANCIAL STATEMENTS | SUBSIDIARES
287
l
a
t
i
p
a
C
e
r
a
h
S
s
r
e
d
l
o
h
e
r
a
h
S
p
i
h
s
r
e
n
w
O
%
o
i
t
a
r
y
t
i
u
q
E
%
)
*
(
d
o
h
t
e
m
n
o
i
t
a
t
u
l
a
v
r
o
n
o
i
t
a
d
i
l
o
s
n
o
C
2,000,000
Eni SpA
100.00
100.00
F.C.
y
c
n
e
r
r
u
C
EUR
EUR
75,000
D-Share SpA
EUR
121,719.25
Agi SpA
Third parties
100.00
55.21
44.79
EUR
3,360,000
Eni SpA
100.00
100.00
EUR
13,427,419.08
Eni SpA
100.00
100.00
EUR
5,160,000
Eni SpA
Third parties
EUR
79,817,238
Eni SpA
49.00
51.00
49.00
100.00
100.00
y
c
n
e
r
r
u
C
l
a
t
i
p
a
C
e
r
a
h
S
s
r
e
d
l
o
h
e
r
a
h
S
p
i
h
s
r
e
n
w
O
%
o
i
t
a
r
y
t
i
u
q
E
%
Co.
F.C.
F.C.
F.C.
F.C.
)
*
(
d
o
h
t
e
m
n
o
i
t
a
t
u
l
a
v
r
o
n
o
i
t
a
d
i
l
o
s
n
o
C
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
Belgium
EUR
50,000,000
USA
USD
0(a)
Eni International BV
Eni Oil Holdings BV
D-Share SpA
99.90
0.10
100.00
100.00
F.C.
Belgium
USD 1,480,365,336
Eni International BV
Eni SpA
66.39
33.61
100.00
Dover, Delaware
(USA)
USA
USD
15,000,000
Eni Petroleum Co Inc
100.00
100.00
Dublin
(Ireland)
Amsterdam
(Netherlands)
London
(United Kingdom)
Houston
(USA)
Ireland
EUR
500,000,000
Eni SpA
100.00
100.00
Netherlands
EUR
641,683,425
Eni SpA
100.00
100.00
United Kingdom GBP
50,000
Eni SpA
Eni UK Ltd
99.99
(..)
100.00
USA
USD
100
Eni Petroleum Co Inc
100.00
100.00
Corporate and Other activities
Corporate and financial companies
IN ITALY
e
m
a
n
y
n
a
p
m
o
C
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
Agenzia Giornalistica Italia SpA
Rome
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
Italy
Italy
Italy
Italy
Italy
Italy
Italy
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
Milan
Milan
San Donato
Milanese (MI)
San Donato
Milanese (MI)
San Donato
Milanese (MI)
San Donato
Milanese (MI)
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
Bruxelles
(Belgium)
New York
(USA)
Bruxelles
(Belgium)
D-Service Media Srl
(in liquidation)
D-Share SpA
Eni Corporate University SpA
EniServizi SpA
Serfactoring SpA
Servizi Aerei SpA
OUTSIDE ITALY
e
m
a
n
y
n
a
p
m
o
C
Banque Eni SA
D-Share USA Corp.
Eni Finance International SA
Eni Finance USA Inc
Eni Insurance DAC
Eni International BV
Eni International Resources Ltd
Eni Next Llc
(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.
(a)Shares without nominal value.
ANNEX TO FINANCIAL STATEMENTS | SUBSIDIARESEni Annual Report 2019
288
Other activities
IN ITALY
e
m
a
n
y
n
a
p
m
o
C
Anic Partecipazioni SpA
(in liquidation)
Eni Energia Srl
Eni Energy Activities Srl
Eni New Energy SpA
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
Gela (CL)
San Donato
Milanese (MI)
San Donato
Milanese (MI)
San Donato
Milanese (MI)
Eni Rewind SpA
(former Syndial Servizi Ambientali SpA)
San Donato
Milanese (MI)
Gela (CL)
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
Italy
Italy
Italy
Italy
Italy
Italy
y
c
n
e
r
r
u
C
l
a
t
i
p
a
C
e
r
a
h
S
s
r
e
d
l
o
h
e
r
a
h
S
EUR
23,519,847.16
Eni Rewind SpA
Third parties
Eni SpA
10,000
50,000
Eni SpA
EUR
EUR
EUR
o
i
t
a
r
y
t
i
u
q
E
%
p
i
h
s
r
e
n
w
O
%
99.97
0.03
100.00
100.00
9,296,000
Eni SpA
100.00
100.00
EUR 425,343,731.50
EUR
1,300,000
Eni SpA
Third parties
Eni Rewind SpA
Third parties
100.00
99.99
(..)
52.00
48.00
Assemini (CA)
Italy
EUR
5,518,620.64
Eni Rewind SpA
100.00
100.00
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
Nur-Sultan
(Kazakhstan)
Amsterdam
(Netherlands)
Cairo
(Egypt)
Karachi
(Pakistan)
Dover, Delaware
(USA)
USA
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
y
c
n
e
r
r
u
C
l
a
t
i
p
a
C
e
r
a
h
S
s
r
e
d
l
o
h
e
r
a
h
S
p
i
h
s
r
e
n
w
O
%
o
i
t
a
r
y
t
i
u
q
E
%
Kazakhstan
KZT
7,963,200,000 Windirect BV
100.00
100.00
Netherlands
EUR
20,000
Eni International BV
100.00
100.00
Egypt
EGP
250,000
Eni International BV
Ieoc Exploration BV
Ieoc Production BV
Eni International BV
Eni Oil Hold. BV
Eni Pakistan Ltd (M)
99.98
0.01
0.01
99.98
0.01
0.01
USD
100
Eni Petroleum Co Inc
100.00
Amsterdam
(Netherlands)
Coira
(Switzerland)
Amsterdam
(Netherlands)
Netherlands
EUR
20,000
Eni International BV
100.00
Switzerland
CHF
1,550,000
Eni Rewind SpA
100.00
Netherlands
EUR
10,000
Eni International BV
100.00
100.00
)
*
(
d
o
h
t
e
m
n
o
i
t
a
t
u
l
a
v
r
o
n
o
i
t
a
d
i
l
o
s
n
o
C
Eq.
Co.
Co.
F.C.
F.C.
Eq.
F.C.
)
*
(
d
o
h
t
e
m
n
o
i
t
a
t
u
l
a
v
r
o
n
o
i
t
a
d
i
l
o
s
n
o
C
F.C.
F.C.
Eq.
Eq.
Eq.
Eq.
F.C.
Industria Siciliana Acido
Fosforico - ISAF - SpA
(in liquidation)
Ing. Luigi Conti Vecchi SpA
OUTSIDE ITALY
e
m
a
n
y
n
a
p
m
o
C
Arm Wind Llp
Eni Energy Solutions BV
Eni New Energy Egypt SAE
Eni New Energy US Inc
Eni Rewind International BV
Oleodotto del Reno SA
Windirect BV
Eni New Energy Pakistan (Private) Ltd Saddar Town-
Pakistan
PKR
136,000,000
100.00
F.C.
(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.
ANNEX TO FINANCIAL STATEMENTS | SUBSIDIARES
JOINT ARRANGEMENTS AND ASSOCIATES
Exploration & Production
IN ITALY
e
m
a
n
y
n
a
p
m
o
C
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
f
o
y
r
t
n
u
o
C
n
o
i
t
a
r
e
p
o
y
c
n
e
r
r
u
C
l
a
t
i
p
a
C
e
r
a
h
S
s
r
e
d
l
o
h
e
r
a
h
S
Mozambique Rovuma Venture SpA(†)
San Donato
Milanese (MI)
Mozambique
EUR
20,000,000
Eni SpA
Third parties
OUTSIDE ITALY
e
m
a
n
y
n
a
p
m
o
C
Agiba Petroleum Co(†)
Angola LNG Ltd
Ashrafi Island Petroleum Co
Barentsmorneftegaz Sàrl(†)
Cabo Delgado Gas Development
Limitada(†)
Cardón IV SA(†)
Compañia Agua Plana SA
Coral FLNG SA
Coral South FLNG DMCC
East Delta Gas Co
(in liquidation)
East Kanayis Petroleum Co(†)
East Obaiyed Petroleum Co(†)
El Temsah Petroleum Co
El-Fayrouz Petroleum Co(†)
(in liquidation)
Fedynskmorneftegaz Sàrl(†)
Isatay Operating Company Llp(†)
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
Cairo
(Egypt)
Hamilton
(Bermuda)
Cairo
(Egypt)
Luxembourg
(Luxembourg)
Maputo
(Mozambique)
Caracas
(Venezuela)
Caracas
(Venezuela)
Maputo
(Mozambique)
Dubai
(United Arab
Emirates)
Cairo
(Egypt)
Cairo
(Egypt)
Cairo
(Egypt)
Cairo
(Egypt)
Cairo
(Egypt)
Luxembourg
(Luxembourg)
Nur-Sultan
(Kazakhstan)
f
o
y
r
t
n
u
o
C
n
o
i
t
a
r
e
p
o
Egypt
y
c
n
e
r
r
u
C
EGP
l
a
t
i
p
a
C
e
r
a
h
S
s
r
e
d
l
o
h
e
r
a
h
S
20,000
Angola
USD
9,952,000,000
Egypt
Russia
EGP
USD
20,000
20,000
Mozambique
MZN
2,500,000
Venezuela
Venezuela
VES
VES
172,10
0,001
Mozambique
MZN
100,000,000
United Arab
Emirates
AED
500,000
Egypt
Egypt
Egypt
Egypt
Egypt
Russia
EGP
EGP
EGP
EGP
EGP
USD
20,000
20,000
20,000
20,000
20,000
20,000
Kazakhstan
KZT
400,000
Karachaganak Petroleum Operating BV Amsterdam
Kazakhstan
EUR
20,000
Karachaganak Project
Development Ltd (KPD)
Khaleej Petroleum Co Wll
(Netherlands)
Reading,
Berkshire
(United Kingdom)
Safat
(Kuwait)
United
Kingdom
GBP
100
Kuwait
KWD
250,000
(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.
(†) Jointly controlled entity.
Ieoc Production BV
Third parties
Eni Angola Prod. BV
Third parties
Ieoc Production BV
Third parties
Eni Energy Russia BV
Third parties
Eni Mozambique LNG H. BV
Third parties
Eni Venezuela BV
Third parties
Eni Venezuela BV
Third parties
Eni Mozambique LNG H. BV
Third parties
Eni Mozambique LNG H. BV
Third parties
Ieoc Production BV
Third parties
Ieoc Production BV
Third parties
Ieoc SpA
Third parties
Ieoc Production BV
Third parties
Ieoc Exploration BV
Third parties
Eni Energy Russia BV
Third parties
Eni Isatay BV
Third parties
Agip Karachaganak BV
Third parties
Agip Karachaganak BV
Third parties
Eni Middle E. Ltd
Third parties
289
o
i
t
a
r
y
t
i
u
q
E
%
n
o
i
t
a
d
i
l
o
s
n
o
C
n
o
i
t
a
t
u
l
a
v
r
o
)
*
(
d
o
h
t
e
m
35.71
J.O.
o
i
t
a
r
y
t
i
u
q
E
%
n
o
i
t
a
d
i
l
o
s
n
o
C
n
o
i
t
a
t
u
l
a
v
r
o
)
*
(
d
o
h
t
e
m
Co.
Eq.
Co.
Eq.
Co.
Eq.
Co.
Eq.
Eq.
Co.
Co.
Co.
Co.
Co.
Eq.
Co.
Co.
Eq.
Eq.
p
i
h
s
r
e
n
w
O
%
35.71
64.29
p
i
h
s
r
e
n
w
O
%
50.00
50.00
13.60
86.40
25.00
75.00
33.33
66.67
50.00
50.00
50.00
50.00
26.00
74.00
25.00
75.00
25.00
75.00
37.50
62.50
50.00
50.00
50.00
50.00
25.00
75.00
50.00
50.00
33.33
66.67
50.00
50.00
29.25
70.75
38.00
62.00
49.00
51.00
ANNEX TO FINANCIAL STATEMENTS | JOINT ARRANGEMENTS AND ASSOCIATESEni Annual Report 2019
290
e
m
a
n
y
n
a
p
m
o
C
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
Liberty National Development Co Llc Wilmington
Mediterranean Gas Co
Meleiha Petroleum Company(†)
Mellitah Oil & Gas BV(†)
Nile Delta Oil Co Nidoco
Norpipe Terminal Holdco Ltd
North Bardawil Petroleum Co
North El Burg Petroleum Co
Petrobel Belayim Petroleum Co(†)
PetroBicentenario SA(†)
PetroJunín SA(†)
PetroSucre SA
Pharaonic Petroleum Co
Point Resources FPSO AS
Point Resources FPSO Holding AS
Port Said Petroleum Co(†)
PR Jotun DA
Raml Petroleum Co
Ras Qattara Petroleum Co
Rovuma Basin LNG Land Limitada(†)
(USA)
Cairo
(Egypt)
Cairo
(Egypt)
Amsterdam
(Netherlands)
Cairo
(Egypt)
London
(United Kingdom)
Cairo
(Egypt)
Cairo
(Egypt)
Cairo
(Egypt)
Caracas
(Venezuela)
Caracas
(Venezuela)
Caracas
(Venezuela)
Cairo
(Egypt)
Sandnes
(Norway)
Sandnes
(Norway)
Cairo
(Egypt)
Sandnes
(Norway)
Cairo
(Egypt)
Cairo
(Egypt)
Maputo
(Mozambique)
Rovuma LNG SA
Shorouk Petroleum Company
Société Centrale Electrique
du Congo SA
Société Italo Tunisienne
d’Exploitation Pétrolière SA(†)
Sodeps - Société de Developpement
et d’Exploitation du Permis du Sud SA(†)
Tecninco Engineering
Contractors Llp(†)
Thekah Petroleum Co
(in liquidation)
United Gas Derivatives Co
Vår Energi AS(†)
Vår Energi Marine AS
(Mozambique)
Maputo
(Mozambique)
Cairo
(Egypt)
Pointe-Noire
(Republic
of the Congo)
Tunisi
(Tunisia)
Tunisi
(Tunisia)
Aksai
(Kazakhstan)
Il Cairo
(Egypt)
New Cairo
(Egypt)
Forus
(Norway)
Sandnes
(Norway)
f
o
y
r
t
n
u
o
C
n
o
i
t
a
r
e
p
o
USA
Egypt
Egypt
Libya
Egypt
Norway
Egypt
Egypt
Egypt
Venezuela
Venezuela
Venezuela
Egypt
y
c
n
e
r
r
u
C
USD
EGP
EGP
EUR
EGP
GBP
EGP
EGP
EGP
VES
VES
VES
EGP
l
a
t
i
p
a
C
e
r
a
h
S
0(a)
s
r
e
d
l
o
h
e
r
a
h
S
Eni Oil & Gas Inc
Third parties
20,000 Ieoc Production BV
Third parties
20,000 Ieoc Production BV
Third parties
20,000 Eni North Africa BV
Third parties
20,000 Ieoc Production BV
Third parties
55.69 Eni SpA
Third parties
20,000 Ieoc Exploration BV
Third parties
20,000 Ieoc SpA
Third parties
20,000 Ieoc Production BV
Third parties
3,790 Eni Lasmo Plc
Third parties
24,021 Eni Lasmo Plc
Third parties
2,203 Eni Venezuela BV
Third parties
20,000 Ieoc Production BV
Third parties
Norway
NOK
150,100,000 PR FPSO Holding AS
Norway
Egypt
Norway
Egypt
Egypt
NOK
EGP
NOK
EGP
EGP
Mozambique
MZN
Mozambique
MZN
Egypt
Republic
of the Congo
Tunisia
Tunisia
EGP
XAF
TND
TND
60,000 Vår Energi AS
20,000 Ieoc Production BV
0(a)
Third parties
PR FPSO AS
PR FPSO Holding AS
20,000 Ieoc Production BV
Third parties
20,000 Ieoc Production BV
Third parties
140,000 Mozambique Rovuma
Venture SpA
Third parties
50,000 Eni Mozambique LNG H. BV
Third parties
100,000,000 Eni Mozambique LNG H. BV
Third parties
20,000 Ieoc Production BV
Third parties
44,732,000,000 Eni Congo SA
Third parties
5,000,000 Eni Tunisia BV
Third parties
100,000 Eni Tunisia BV
Third parties
Kazakhstan
KZT
29,478,455 EniProgetti SpA
Egypt
Egypt
Third parties
EGP
20,000 Ieoc Exploration BV
Third parties
USD
153,000,000 Eni International BV
Third parties
Norway
NOK
399,425,000 Eni International BV
Third parties
Norway
NOK
61,000,000 Vår Energi AS
o
i
t
a
r
y
t
i
u
q
E
%
p
i
h
s
r
e
n
w
O
%
32.50
67.50
25.00
75.00
50.00
50.00
50.00
50.00
37.50
62.50
14.20
85.80
30.00
70.00
25.00
75.00
50.00
50.00
40.00
60.00
40.00
60.00
26.00
74.00
25.00
75.00
100.00
100.00
50.00
50.00
95.00
5.00
22.50
77.50
37.50
62.50
33.33
66.67
25.00
75.00
25.00
75.00
25.00
75.00
20.00
80.00
50.00
50.00
50.00
50.00
49.00
51.00
25.00
75.00
33.33
66.67
69.60
30.40
100.00
n
o
i
t
a
d
i
l
o
s
n
o
C
n
o
i
t
a
t
u
l
a
v
r
o
)
*
(
d
o
h
t
e
m
Eq.
Co.
Co.
Co.
Co.
Eq.
Co.
Co.
Co.
Eq.
Eq.
Eq.
Co.
Co.
Co.
Co.
Co.
Eq.
Eq.
Co.
Eq.
Eq.
Co.
Eq.
Co.
Eq.
Eq.
Rovuma LNG Investments (DIFC) Ltd Maputo
Mozambique
USD
(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.
(†) Jointly controlled entity.
(a) Shares without nominal value.
ANNEX TO FINANCIAL STATEMENTS | JOINT ARRANGEMENTS AND ASSOCIATES
e
m
a
n
y
n
a
p
m
o
C
e
c
ffi
o
d
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r
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t
s
i
g
e
R
VIC CBM Ltd(†)
Virginia Indonesia Co CBM Ltd(†)
West Ashrafi Petroleum Co(†)
(in liquidation)
London
(United Kingdom)
London
(United Kingdom)
Cairo
(Egypt)
f
o
y
r
t
n
u
o
C
n
o
i
t
a
r
e
p
o
Indonesia
Indonesia
Egypt
y
c
n
e
r
r
u
C
USD
USD
EGP
l
a
t
i
p
a
C
e
r
a
h
S
s
r
e
d
l
o
h
e
r
a
h
S
52,315,912 Eni Lasmo Plc
Third parties
25,631,640 Eni Lasmo Plc
Third parties
20,000 Ieoc Exploration BV
Third parties
Gas & Power
IN ITALY
e
m
a
n
y
n
a
p
m
o
C
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
Mariconsult SpA(†)
Milan
Società EniPower Ferrara Srl(†)
Transmed SpA(†)
San Donato
Milanese (MI)
Milan
OUTSIDE ITALY
e
m
a
n
y
n
a
p
m
o
C
Angola LNG Supply Services Llc
Blue Stream Pipeline Co BV(†)
Gas Distribution Company
of Thessaloniki-Thessaly SA(†)
GreenStream BV(†)
Premium Multiservices SA
SAMCO Sagl
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
Wilmington
(USA)
Amsterdam
(Netherlands)
Ampelokipi
Menemeni
(Greece)
Amsterdam
(Netherlands)
Tunisi
(Tunisia)
Lugano
(Switzerland)
f
o
y
r
t
n
u
o
C
n
o
i
t
a
r
e
p
o
Italy
Italy
Italy
y
c
n
e
r
r
u
C
l
a
t
i
p
a
C
e
r
a
h
S
s
r
e
d
l
o
h
e
r
a
h
S
EUR
120,000
EUR
140,000,000
EUR
240,000
Eni SpA
Third parties
EniPower SpA
Third parties
Eni SpA
Third parties
f
o
y
r
t
n
u
o
C
n
o
i
t
a
r
e
p
o
USA
Russia
y
c
n
e
r
r
u
C
USD
USD
l
a
t
i
p
a
C
e
r
a
h
S
s
r
e
d
l
o
h
e
r
a
h
S
19,278,782
22,000
Greece
EUR
247,127,605
Libya
EUR
200,000,000
Tunisia
TND
200,000
Switzerland
CHF
20,000
Eni USA Gas M. Llc
Third parties
Eni International BV
Third parties
Eni gas e luce SpA
Third parties
Eni North Africa BV
Third parties
Sergaz SA
Third parties
Eni International BV
Transmed. Pip. Co Ltd
Third parties
Eni SpA
Third parties
Eni SpA
Third parties
291
n
o
i
t
a
d
i
l
o
s
n
o
C
n
o
i
t
a
t
u
l
a
v
r
o
)
*
(
d
o
h
t
e
m
Eq.
Eq.
Co.
)
*
(
d
o
h
t
e
m
n
o
i
t
a
t
u
l
a
v
r
o
n
o
i
t
a
d
i
l
o
s
n
o
C
Eq.
J.O.
Eq.
n
o
i
t
a
d
i
l
o
s
n
o
C
n
o
i
t
a
t
u
l
a
v
r
o
)
*
(
d
o
h
t
e
m
Eq.
J.O.
Eq.
J.O.
Eq.
Eq.
J.O.
Eq.
o
i
t
a
r
y
t
i
u
q
E
%
o
i
t
a
r
y
t
i
u
q
E
%
51.00
o
i
t
a
r
y
t
i
u
q
E
%
74.62(a)
50.00
50.00
p
i
h
s
r
e
n
w
O
%
50.00
50.00
50.00
50.00
50.00
50.00
p
i
h
s
r
e
n
w
O
%
50.00
50.00
51.00
49.00
50.00
50.00
p
i
h
s
r
e
n
w
O
%
13.60
86.40
50.00
50.00
49.00
51.00
50.00
50.00
49.99
50.01
5.00
90.00
5.00
50.00
50.00
50,00
50,00
Transmediterranean Pipeline Co Ltd(†)(3) St. Helier
(Jersey)
Unión Fenosa Gas SA(†)
Madrid
(Spain)
Jersey
USD
10,310,000
Spain
EUR
32,772,000
(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.
(†) Jointly controlled entity.
(3) Company that benefits from a privileged tax regime pursuant to art. 167, paragraph 4 of the D.P.R. of December 22, 1986, n. 917: the company is subjected to taxation in Italy because it is included in Eni's tax
return. The company is considered as a controlled entity pursuant to art. 167, paragraph 3 of the TUIR.
(a) Equity ratio equal to the Eni's working interest.
ANNEX TO FINANCIAL STATEMENTS | JOINT ARRANGEMENTS AND ASSOCIATESEni Annual Report 2019
292
Refining & Marketing and Chemicals
Refining & Marketing
IN ITALY
e
m
a
n
y
n
a
p
m
o
C
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
y
c
n
e
r
r
u
C
l
a
t
i
p
a
C
e
r
a
h
S
s
r
e
d
l
o
h
e
r
a
h
S
p
i
h
s
r
e
n
w
O
%
o
i
t
a
r
y
t
i
u
q
E
%
)
*
(
d
o
h
t
e
m
n
o
i
t
a
t
u
l
a
v
r
o
n
o
i
t
a
d
i
l
o
s
n
o
C
Arezzo Gas SpA(†)
Arezzo
Italy
EUR
394,000
CePIM Centro Padano
Interscambio Merci SpA
Fontevivo (PR)
Italy
EUR
6,642,928.32
Consorzio Operatori GPL di Napoli
Napoli
Costiero Gas Livorno SpA(†)
Livorno
Italy
Italy
EUR
102,000
EUR
26,000,000
Disma SpA
Segrate (MI)
Italy
EUR
2,600,000
Eni Fuel SpA
Third parties
Ecofuel SpA
Third parties
Eni Fuel SpA
Third parties
Eni Fuel SpA
Third parties
Eni Fuel SpA
Third parties
Livorno LNG Terminal SpA
Livorno
Porto Petroli di Genova SpA
Genova
Italy
Italy
EUR
200,000
Costiero Gas Liv. SpA
Third parties
EUR
2,068,000
Raffineria di Milazzo ScpA(†)
Milazzo (ME)
Italy
EUR
171,143,000
Seram SpA
Fiumicino (RM)
Italy
EUR
852,000
Sigea Sistema Integrato
Genova Arquata SpA
Genova
Società Oleodotti Meridionali - SOM
SpA(†)
San Donato
Milanese (MI)
Italy
Italy
EUR
3,326,900
EUR
3,085,000
Ecofuel SpA
Third parties
Eni SpA
Third parties
Eni SpA
Third parties
Ecofuel SpA
Third parties
Eni SpA
Third parties
Eq.
Eq.
Co.
65.00
J.O.
50.00
50.00
44.78
55.22
25.00
75.00
65.00
35.00
25.00
75.00
50.00
50.00
40.50
59.50
50.00
50.00
25.00
75.00
35.00
65.00
70.00
30.00
50.00
70.00
Eq.
Eq.
Eq.
J.O.
Co.
Eq.
J.O.
J.O.
Termica Milazzo Srl(†)
Milazzo (ME)
Italy
EUR
100,000
Raff. Milazzo ScpA
100.00
50.00
(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.
(†) Jointly controlled entity.
ANNEX TO FINANCIAL STATEMENTS | JOINT ARRANGEMENTS AND ASSOCIATES
293
o
i
t
a
r
y
t
i
u
q
E
%
20.00
)
*
(
d
o
h
t
e
m
n
o
i
t
a
t
u
l
a
v
r
o
n
o
i
t
a
d
i
l
o
s
n
o
C
Eq.
Eq.
Eq.
J.O.
Eq.
Co.
Eq.
Co.
Eq.
Eq.
Co.
50.00
J.O.
Eq.
Eq.
OUTSIDE ITALY
e
m
a
n
y
n
a
p
m
o
C
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
y
c
n
e
r
r
u
C
l
a
t
i
p
a
C
e
r
a
h
S
s
r
e
d
l
o
h
e
r
a
h
S
Abu Dhabi Oil Refining Company
(TAKREER)
ADNOC Global Trading Ltd
Abu Dhabi
(United Arab
Emirates)
Abu Dhabi
(United Arab
Emirates)
United Arab
Emirates
United Arab
Emirates
AED
500,000,000
Eni Abu Dhabi R&T BV
Third parties
USD
1,000
Eni Abu Dhabi R&T BV
Third parties
AET - Raffineriebeteiligungsgesellschaft
mbH(†)
Bayernoil Raffineriegesellschaft
mbH(†)
Schwedt
(Germany)
Vohburg
(Germany)
City Carburoil SA(†)
Egyptian International
Gas Technology Co
ENEOS Italsing Pte Ltd
Fuelling Aviation Services GIE
Mediterranée Bitumes SA
Routex BV
Saraco SA
Supermetanol CA(†)
TBG Tanklager
Betriebsgesellschaft GmbH(†)
Weat Electronic Datenservice GmbH
Rivera
(Switzerland)
Cairo
(Egypt)
Singapore
(Singapore)
Tremblay en
France
(France)
Tunisi
(Tunisia)
Amsterdam
(Netherlands)
Meyrin
(Switzerland)
Jose Puerto
La Cruz
(Venezuela)
Salzburg
(Austria)
Düsseldorf
(Germany)
Germany
EUR
27,000
Germany
EUR
10,226,000
Switzerland
CHF
6,000,000
Egypt
EGP
100,000,000
Singapore
SGD
12,000,000
Eni Deutsch. GmbH
Third parties
Eni Deutsch. GmbH
Third parties
Eni Suisse SA
Third parties
Eni International BV
Third parties
Eni International BV
Third parties
France
EUR
1
Eni France Sàrl
Third parties
Tunisia
TND
1,000,000
Netherlands
EUR
67,500
Switzerland
CHF
420,000
Venezuela
VES
120.867
Austria
EUR
43,603.70
Germany
EUR
409,034
Eni International BV
Third parties
Eni International BV
Third parties
Eni Suisse SA
Third parties
Ecofuel SpA
Supermetanol CA
Third parties
Eni Marketing A. GmbH
Third parties
Eni Deutsch. GmbH
Third parties
p
i
h
s
r
e
n
w
O
%
20.00
80.00
20.00
80.00
33.33
66.67
20.00
80.00
49.91
50.09
40.00
60.00
22.50
77.50
25.00
75.00
34.00
66.00
20.00
80.00
20.00
80.00
(a)
34.51
30.07
35.42
50.00
50.00
20.00
80.00
(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.
(†) Jointly controlled entity.
(a) Controlling interest: Ecofuel SpA
Third parties
50.00
50.00
ANNEX TO FINANCIAL STATEMENTS | JOINT ARRANGEMENTS AND ASSOCIATESEni Annual Report 2019
294
Chemical
IN ITALY
e
m
a
n
y
n
a
p
m
o
C
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
y
c
n
e
r
r
u
C
l
a
t
i
p
a
C
e
r
a
h
S
s
r
e
d
l
o
h
e
r
a
h
S
p
i
h
s
r
e
n
w
O
%
o
i
t
a
r
y
t
i
u
q
E
%
Brindisi Servizi Generali Scarl
Brindisi
Italy
EUR
1,549,060
IFM Ferrara ScpA
Ferrara
Italy
EUR
5,270,466
Matrìca SpA(†)
Novamont SpA
Priolo Servizi ScpA
Porto Torres
(SS)
Novara
Melilli
(SR)
Italy
Italy
Italy
EUR
37,500,000
EUR
13,333,500
EUR
28,100,000
Ravenna Servizi Industriali ScpA
Ravenna
Italy
EUR
5,597,400
Servizi Porto Marghera Scarl
Porto Marghera
(VE)
Italy
EUR
8,695.718
Versalis SpA
Eni Rewind SpA
EniPower SpA
Third parties
Versalis SpA
Eni Rewind SpA
S.E.F. Srl
Third parties
Versalis SpA
Third parties
Versalis SpA
Third parties
Versalis SpA
Eni Rewind SpA
Third parties
Versalis SpA
EniPower SpA
Ecofuel SpA
Third parties
Versalis SpA
Eni Rewind SpA
Third parties
OUTSIDE ITALY
e
m
a
n
y
n
a
p
m
o
C
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
y
c
n
e
r
r
u
C
l
a
t
i
p
a
C
e
r
a
h
S
s
r
e
d
l
o
h
e
r
a
h
S
Lotte Versalis Elastomers Co Ltd(†)
Versalis Zeal Ltd(†)
VPM Oilfield Specialty
Chemicals Llc(†)
Yeosu
(South Korea)
Takoradi
(Ghana)
Abu Dhabi
(United Arab
Emirates)
South Korea
KRW 401,800,000,000
Ghana
United Arab
Emirates
GHS
AED
5,650,000
1,000,000
Versalis SpA
Third parties
Versalis International SA
Third parties
Versalis SpA
Third parties
49.00
20.20
8.90
21.90
19.74
11.58
10.70
57.98
50.00
50.00
25.00
75.00
33.11
4.61
62.28
42.13
30.37
1.85
25.65
48.44
38.39
13.17
p
i
h
s
r
e
n
w
O
%
50.00
50.00
80.00
20.00
49.00
51.00
o
i
t
a
r
y
t
i
u
q
E
%
(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.
(†) Jointly controlled entity.
)
*
(
d
o
h
t
e
m
n
o
i
t
a
t
u
l
a
v
r
o
n
o
i
t
a
d
i
l
o
s
n
o
C
Eq.
Eq.
Eq.
Eq.
Eq.
Eq.
Eq.
)
*
(
d
o
h
t
e
m
n
o
i
t
a
t
u
l
a
v
r
o
n
o
i
t
a
d
i
l
o
s
n
o
C
Eq.
Eq.
Eq.
ANNEX TO FINANCIAL STATEMENTS | JOINT ARRANGEMENTS AND ASSOCIATES
295
)
*
(
d
o
h
t
e
m
n
o
i
t
a
t
u
l
a
v
r
o
n
o
i
t
a
d
i
l
o
s
n
o
C
Eq.
Eq.
)
*
(
d
o
h
t
e
m
n
o
i
t
a
t
u
l
a
v
r
o
n
o
i
t
a
d
i
l
o
s
n
o
C
Eq.
Eq.
Eq.
)
*
(
d
o
h
t
e
m
n
o
i
t
a
t
u
l
a
v
r
o
n
o
i
t
a
d
i
l
o
s
n
o
C
o
i
t
a
r
y
t
i
u
q
E
%
o
i
t
a
r
y
t
i
u
q
E
%
o
i
t
a
r
y
t
i
u
q
E
%
Corporate and Other activities
Corporate and financial companies
OUTSIDE ITALY
e
m
a
n
y
n
a
p
m
o
C
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
Commonwealth Fusion Systems Llc(a) Wilmington
Form Energy Inc(b)
(USA)
Somemrville
(USA)
Other activities
IN ITALY
e
m
a
n
y
n
a
p
m
o
C
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
USA
USA
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
Ottana Sviluppo ScpA
(in bankruptcy)
Nuoro
Italy
Progetto Nuraghe Scarl
Porto Torres (SS)
Italy
y
c
n
e
r
r
u
C
l
a
t
i
p
a
C
e
r
a
h
S
s
r
e
d
l
o
h
e
r
a
h
S
USD
115,000,519
USD 50,889,548.24
Eni Next Llc
Third parties
Eni Next Llc
Third parties
p
i
h
s
r
e
n
w
O
%
y
c
n
e
r
r
u
C
EUR
EUR
l
a
t
i
p
a
C
e
r
a
h
S
s
r
e
d
l
o
h
e
r
a
h
S
516,000
10,000
p
i
h
s
r
e
n
w
O
%
30.00
70.00
48.55
51.45
30.54
1.46
68.00
(c)
Eni Rewind SpA
Third parties
Eni Rewind SpA
Third parties
Eni SpA
Saipem SpA
Third parties
Saipem SpA(#)(†)
San Donato
Milanese (MI)
Italy
EUR 2,191,384,693
OUTSIDE ITALY
e
m
a
n
y
n
a
p
m
o
C
Ayla Energy Ltd(†)
Grid Edge (Private) Ltd(†)
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
y
c
n
e
r
r
u
C
l
a
t
i
p
a
C
e
r
a
h
S
s
r
e
d
l
o
h
e
r
a
h
S
p
i
h
s
r
e
n
w
O
%
London
(United Kingdom)
Saddar
Town - Karachi
(Pakistan)
United Kingdom USD
1,000
Pakistan
PKR
1,200,000
Eni Energy
Solutions BV
Third parties
50.00
50.00
Eni International BV
Third parties
40.00
60.00
Eni International BV
Third parties
50.00
50.00
Eni Energy
Solutions BV
Third parties
50.00
50.00
Eq.
Eq.
Eq.
Eq.
Société Energies Renouvelables
Eni-ETAP SA(†)
Tunisi
(Tunisia)
Tunisia
TND
1,000,000
Solenova Ltd(†)
London
(United Kingdom)
United Kingdom USD
20,000
(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.
(#) Company with shares quoted in the regulated market of Italy or of other EU Countries.
(†) Jointly controlled entity.
(a) The ownership cannot be determined. The capital subscribed by Eni Next Llc amounts to $50 million.
(b) The ownership cannot be determined. The capital subscribed by Eni Next Llc amounts to $15 million.
(c) Controlling interest: Eni SpA
Third parties
30.99
69.01
ANNEX TO FINANCIAL STATEMENTS | JOINT ARRANGEMENTS AND ASSOCIATESEni Annual Report 2019
296
■ OTHER SIGNIFICANT INVESTMENTS
Exploration & Production
IN ITALY
e
m
a
n
y
n
a
p
m
o
C
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
Consorzio Universitario in Ingegneria
per la Qualità e l’Innovazione
Pisa
Italy
OUTSIDE ITALY
e
m
a
n
y
n
a
p
m
o
C
Administradora del Golfo de Paria Este SA
Brass LNG Ltd
Darwin LNG Pty Ltd
New Liberty Residential Co Llc
Nigeria LNG Ltd
North Caspian Operating Co NV
OPCO - Sociedade Operacional Angola LNG SA
Petrolera Güiria SA
SOMG - Sociedade de Operações
e Manutenção de Gasodutos SA
Torsina Oil Co
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
Caracas
(Venezuela)
Lagos
(Nigeria)
West Perth
(Australia)
West Trenton
(USA)
Port Harcourt
(Nigeria)
Amsterdam
(Netherlands)
Luanda
(Angola)
Caracas
(Venezuela)
Luanda
(Angola)
Cairo
(Egypt)
y
c
n
e
r
r
u
C
EUR
y
c
n
e
r
r
u
C
VES
USD
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
Venezuela
Nigeria
Angola
Venezuela
Angola
Egypt
AOA
VES
AOA
EGP
l
a
t
i
p
a
C
e
r
a
h
S
s
r
e
d
l
o
h
e
r
a
h
S
p
i
h
s
r
e
n
w
O
%
)
*
(
d
o
h
t
e
m
n
o
i
t
a
t
u
l
a
v
r
o
n
o
i
t
a
d
i
l
o
s
n
o
C
135,000
Eni SpA
Third parties
20.00
80.00
F.V.
l
a
t
i
p
a
C
e
r
a
h
S
s
r
e
d
l
o
h
e
r
a
h
S
0.001
1,000,000
Eni Venezuela BV
Third parties
Eni Int. NA NV Sàrl
Third parties
Eni Int. NA NV Sàrl
Third parties
Agip Caspian Sea BV
Third parties
Eni Angola Prod. BV
Third parties
7,400,000
10
Eni Venezuela BV
Third parties
7,400,000
Eni Angola Prod. BV
Third parties
20,000
Ieoc Production BV
Third parties
)
*
(
d
o
h
t
e
m
n
o
i
t
a
t
u
l
a
v
r
o
n
o
i
t
a
d
i
l
o
s
n
o
C
F.V.
F.V.
F.V.
F.V.
F.V.
F.V.
F.V.
F.V.
F.V.
F.V.
p
i
h
s
r
e
n
w
O
%
19.50
80.50
20.48
79.52
10.99
89.01
17.50
82.50
10.40
89.60
16.81
83.19
13.60
86.40
19.50
80.50
13.60
86.40
12.50
87.50
Australia
AUD
367,278,503.01
Eni G&P LNG Aus. BV
Third parties
USA
USD
0(a)
Eni Oil & Gas Inc
Third parties
Nigeria
USD
1,138,207,000
Kazakhstan
EUR
128,520
(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.
(a) Shares without nominal value.
ANNEX TO FINANCIAL STATEMENTS | OTHER SIGNIFICANT INVESTMENTS
Gas & Power
OUTSIDE ITALY
e
m
a
N
y
n
a
p
m
o
C
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
y
c
n
e
r
r
u
C
l
a
t
i
p
a
C
e
r
a
h
S
s
r
e
d
l
o
h
e
r
a
h
S
p
i
h
s
r
e
n
w
O
%
297
)
*
(
d
o
h
t
e
m
n
o
i
t
a
t
u
l
a
v
r
o
n
o
i
t
a
d
i
l
o
s
n
o
C
Norsea Gas GmbH
Emden
(Germany)
Germany
EUR
1,533,875.64
Eni International BV
Third parties
13.04
86.96
F.V.
(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.
ANNEX TO FINANCIAL STATEMENTS | OTHER SIGNIFICANT INVESTMENTSEni Annual Report 2019
298
Refining & Marketing and Chemical
Refining & Marketing
IN ITALY
e
m
a
N
y
n
a
p
m
o
C
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
Società Italiana Oleodotti di Gaeta SpA(4)
Rome
Italy
OUTSIDE ITALY
e
m
a
n
y
n
a
p
m
o
C
BFS Berlin Fuelling Services GbR
Compania de Economia Mixta “Austrogas”
Dépôt Pétrolier de Fos SA
Dépôt Pétrolier de la Côte d’Azur SAS
Joint Inspection Group Ltd
S.I.P.G. Société Immobilière Pétrolière
de Gestion Snc
Sistema Integrado de Gestion
de Aceites Usados
Tanklager - Gesellschaft Tegel (TGT) GbR
TAR - Tankanlage Ruemlang AG
Tema Lube Oil Co Ltd
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
Amburgo
(Germany)
Cuenca
(Ecuador)
Fos-Sur-Mer
(France)
Nanterre
(France)
London
(United Kingdom)
Tremblay en France
(France)
Madrid
(Spain)
Hamburg
(Germany)
Ruemlang
(Switzerland)
Accra
(Ghana)
y
c
n
e
r
r
u
C
ITL
y
c
n
e
r
r
u
C
EUR
USD
EUR
EUR
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
Germany
Ecuador
France
France
United Kingdom GBP
France
Spain
Germany
EUR
EUR
EUR
l
a
t
i
p
a
C
e
r
a
h
S
s
r
e
d
l
o
h
e
r
a
h
S
p
i
h
s
r
e
n
w
O
%
)
*
(
d
o
h
t
e
m
n
o
i
t
a
t
u
l
a
v
r
o
n
o
i
t
a
d
i
l
o
s
n
o
C
360,000,000
Eni SpA
Third parties
72.48
27.52
F.V.
l
a
t
i
p
a
C
e
r
a
h
S
s
r
e
d
l
o
h
e
r
a
h
S
89,199
5,665,329
Eni Deutsch. GmbH
Third parties
Eni Ecuador SA
Third parties
3,954,196.40
207,500
Eni France Sàrl
Third parties
Eni France Sàrl
Third parties
0(a)
Eni SpA
Third parties
40.000
175,713
Eni France Sàrl
Third parties
Eni Iberia SLU
Third parties
4,953
Eni Deutsch. GmbH
Third parties
)
*
(
d
o
h
t
e
m
n
o
i
t
a
t
u
l
a
v
r
o
n
o
i
t
a
d
i
l
o
s
n
o
C
F.V.
F.V.
F.V.
F.V.
F.V.
F.V.
F.V.
F.V.
F.V.
F.V.
p
i
h
s
r
e
n
w
O
%
12.50
87.50
13.38
86.62
16.81
83.19
18.00
82.00
12.50
87.50
12.50
87.50
15.44
84.56
12.50
87.50
16.27
83.73
12.00
88.00
Switzerland
CHF
3,259,500
Ghana
GHS
258,309
Eni Suisse SA
Third parties
Eni International BV
Third parties
(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.
(a) Shares without nominal value.
(4) Company under extraordinary administration procedure pursuant to law no. 95 of april 3, 1979. The liquidation was concluded on april 28, 2015. The cancellation has been filed and is pending the
authorization by the Ministry of Economic Development.
ANNEX TO FINANCIAL STATEMENTS | OTHER SIGNIFICANT INVESTMENTS
299
■ CHANGES IN THE SCOPE OF CONSOLIDATION FOR 2019
Fully consolidated subsidiaries
COMPANIES INCLUDED (N. 10)
Eni Abu Dhabi Refining & Trading BV
Amsterdam
Refining & Marketing
Relevancy
Eni Argentina Exploración y Explotación SA
Buenos Aires
Exploration & Production
Relevancy
Eni Bahrain BV
Amsterdam
Exploration & Production
Relevancy
Eni New Energy Pakistan (Private) Ltd
Saddar Town-Karachi
Other activities
Constitution
Eni RAK BV
Eni West Ganal Ltd
SEA SpA
Amsterdam
Exploration & Production
Constitution
London
L'Aquila
Exploration & Production
Constitution
Gas & Power
Acquisition
Relevancy
Versalis Congo Sarlu
Pointe-Noire
Chemical
Eni Energy Solutions BV
Petroven Srl
Amsterdam
Genova
Other activities
Constitution
Refining & Marketing
Acquisition of the control
COMPANIES EXCLUDED (N. 9)
Agip Oil Ecuador BV
Amsterdam
Exploration & Production
Sale
Eni Adfin SpA
(in liquidation)
Eni Denmark BV
Eni India Ltd
Eni Iran BV
Eni Liberia BV
Eni Portugal BV
Eni Ukraine Llc
Rome
Corporate and financial companies Cancellation
Amsterdam
Exploration & Production
Irrelevancy
London
Amsterdam
Amsterdam
Amsterdam
Kiev
Exploration & Production
Irrelevancy
Exploration & Production
Irrelevancy
Exploration & Production
Irrelevancy
Exploration & Production
Irrelevancy
Exploration & Production
Irrelevancy
Eni USA R&M Co Inc
Wilmington
Refining & Marketing
Irrelevancy
Consolidated joint operations
COMPANIES EXCLUDED (N. 1)
Petroven Srl
Genova
Refining & Marketing
Acquisition of the control
ANNEX TO FINANCIAL STATEMENTS | CHANGES IN THE SCOPE OF CONSOLIDATION FOR 2019Eni Annual Report 2019 Eni SpA
Headquarters
Piazzale Enrico Mattei, 1 - Rome - Italy
Capital Stock as of December 31, 2019: € 4,005,358,876.00 fully paid
Tax identification number 00484960588
Branches
Via Emilia, 1 - San Donato Milanese (Milan) - Italy
Piazza Ezio Vanoni, 1 - San Donato Milanese (Milan) - Italy
Contacts
eni.com
+39-0659821
800940924
segreteriasocietaria.azionisti@eni.com
Investor Relations
Piazza Ezio Vanoni, 1 - 20097 San Donato Milanese (Milan)
Tel. +39-0252051651 - Fax +39-0252031929
e-mail: investor.relations@eni.com
Layout and supervision
K-Change - Rome
Printing
Tipografia Facciotti – Rome - Italy