Eni
Annual
Rep ort
2018
FINANCIAL HIGHLIGHTS
Net sales from operations
Operating profit (loss)
Adjusted operating profit (loss)(a)
Adjusted net profit (loss)(a)(b)
Net profit (loss)(b)
Net profit (loss) - discontinued operations(b)
Group net profit (loss)(b) (continuing and discontinued operations)
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
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 2018 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
Gearing
Coverage
Current ratio
Debt coverage
Net Debt/EBITDA adjusted
Dividend pertaining to the year
Total Share Return (TSR)
Pay-out
Dividend yield(c)
(€ million)
(€)
(million)
(€ billion)
(€)
($)
(€)
($)
(€)
($)
(%)
(€ per share)
(%)
2018
75,822
9,983
11,240
4,583
4,126
4,126
13,647
9,119
463
6,506
2,989
2,954
118,373
51,073
8,289
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
3,374
10,117
8,681
442
7,236
2,881
2,880
114,928
48,079
10,916
58,995
49,801
3,394
7,440
13.8
3,601.1
50
2016
55,762
2,157
2,315
(340)
(1,051)
(413)
(1,464)
7,673
9,180
417
7,770
2,881
2,881
124,545
53,086
14,776
67,862
57,910
4,100
6,981
15.5
3,601.1
56
2018
2017
2016
1.15
2.72
1.27
3.00
3.79
8.95
8.5
16
14
10.3
1.4
164.6
45.2
0.83
4.8
72
5.9
0.94
2.12
0.66
1.49
2.81
6.35
4.7
23
18
6.5
1.5
92.7
80.6
0.80
(5.6)
85
5.7
(0.29)
(0.65)
(0.09)
(0.20)
2.13
4.72
0.2
28
22
2.4
1.4
51.9
144.7
0.80
19.2
(197)
5.4
(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
First patent filing application
(number)
2018
11,645
3,040
11,136
5,880
31,701
2017
11,970
4,313
10,916
5,735
32,934
2016
12,494
4,261
10,858
5,923
33,536
(€ million)
(number)
2018
197
43
2017
185
27
2016
161
40
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
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
Volumes of hydrocarbon sent to flaring - upstream
Total volume of oil spills (> 1 barrel)
of which: due to sabotage and terrorism
operational
% produced water reinjected - upstream
Groundwater treated or used in production or reinjected
% of groundwater used in production/reinjected vs. total treated groundwater
Electricity produced from renewable sources
% of recovered waste vs. recoverable waste (Syndial)
OPERATING DATA
EXPLORATION & PRODUCTION
Hydrocarbon production
Net proved reserves of hydrocarbons
Average 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
Refinery throughputs on own account
Average throughput of service stations in Europe
Balanced capacity of refineries
Capacity of biorefineries
Production of biofuels
Production of petrochemical products
Average petrochemical plant utilization rate
(a) Related to consolidated subsidiaries.
(b) Includes Eni’s share in joint ventures and equity-accounted entities.
(c) Three-year average.
(total recordable injuries/worked hours) x 1,000,000
(mmtonnes CO2eq)
(bcm)
(barrels)
(%)
(mmcm)
(%)
(GWh)
(%)
(kboe/d)
(mmboe)
(years)
(%)
($/boe)
(bcm)
(GW)
(TWh)
(mmtonnes)
(%)
(number)
(mmtonnes)
(kliters)
(kbbl/d)
(ktonnes/year)
(ktonnes)
(ktonnes)
(%)
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
1.9
6,362
3,697
2,665
60
4.8
21
19.3
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
2.3
6,559
3,236
3,323
59
4.2
21
16.1
48
2016
0.35
0.34
0.34
0.34
0.29
0.28
0.31
0.38
0.44
0.32
0.50
0.40
0.76
42.15
32.39
5.40
2.35
2.01
22.46
11.17
8.50
1.9
5,913
4,682
1,231
58
3.2
17
13.5
30
2018
2017
2016
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
23.23
1,776
548
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
24.02
1,783
548
360
206
8,955
73
1,759
7,490
11.6
193
2.0
6.2
13.2
86.31
38.43
47.88
8.1
4.7
21.78
37.05
8.59
24.3
5,622
24.52
1,742
548
360
191
8,809
72
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
Scenario and 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
2
4
5
7
12
14
16
20
24
30
50
55
61
63
87
103
104
134
135
1 3 7 |
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 5 9 |
A N N E X
Eni
Annual
Report
2018
Disclaimer
This Annual Report contains certain forward-looking statements in particular under the section “Outlook” regarding capital expenditures, dividends, 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.
Ordinary Shareholders’ Meeting of May 14, 2019.
The extract of the notice convening the meeting was published on April 5, 2019.
ACTIVITIES
Eni engages in oil and natural gas exploration, fields development and production, mainly in Italy, Algeria, Angola, Congo, the United Arab
Emirates, Egypt, Ghana, Libya, Mozambique, Nigeria, Norway, Oman, Kazakhstan, the UK, and the United States, for overall 43 Countries.
Eni sells gas, electricity, LNG and oil products in the 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.
OFFSHORE
TRADING
& SHIPPING
INTERNATIONAL
OIL AND GAS
MARKETS
EXPLORATION
DEVELOPING OIL
AND GAS FIELDS
REFINERIES AND
PETROCHEMICAL
PLANTS
(traditional and green)
FUEL
/BIOFUEL
CHEMICAL
PRODUCTS
/BIO-BASED
CHEMICALS
LIQUEFYING GAS
LUBRICANTS
TRANSMISSION
NETWORK
ONSHORE
RIGASSIFYING LNG
GAS AND
POWER
RENEWABLE
ENERGY
PRODUCTION
POWER
GENERATION
ENI WORLDWIDE PRESENCE
18
5
3
7
13
14
7
11
3
6
1
67 Countries
E&P
G&P
R&M&C
B2B
B2C
16
ACTIVITIES
Eni engages in oil and natural gas exploration, fields development and production, mainly in Italy, Algeria, Angola, Congo, the United Arab
Emirates, Egypt, Ghana, Libya, Mozambique, Nigeria, Norway, Oman, Kazakhstan, the UK, and the United States, for overall 43 Countries.
Eni sells gas, electricity, LNG and oil products in the 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.
REFINERIES AND
PETROCHEMICAL
PLANTS
(traditional and green)
OFFSHORE
TRADING
& SHIPPING
INTERNATIONAL
OIL AND GAS
MARKETS
EXPLORATION
DEVELOPING OIL
AND GAS FIELDS
FUEL
/BIOFUEL
CHEMICAL
PRODUCTS
/BIO-BASED
CHEMICALS
LIQUEFYING GAS
TRANSMISSION
NETWORK
LUBRICANTS
ONSHORE
RIGASSIFYING LNG
GAS AND
POWER
RENEWABLE
ENERGY
PRODUCTION
POWER
GENERATION
ENI WORLDWIDE PRESENCE
18
5
3
7
13
14
7
11
3
6
1
67 Countries
E&P
G&P
R&M&C
B2B
B2C
16
BUSINESS MODEL
Eni’s business model is focused on creating value for its
stakeholders and shareholders. Eni recognizes that the main
challenge in the energy sector is providing efficient and
sustainable access of local communities to energy resources,
while combating climate change. This challenge may trigger
new paradigms of development affecting patterns of
consumption and supply, as well as on industrial processes.
In this framework, Eni has adopted a systemic approach to
pursue efficiency, resilience and growth, which organically
integrates sustainability to make it business, incorporates
emerging trends of decarbonisation and inclusive development
including them in its industrial plan and in the operating model.
Eni, therefore, adopts a business model, fuelled by the
application of own innovative technologies and the digitalization
process, leveraging on the following levers:
1 operational excellence,
2 carbon neutrality in the long term,
3 promotion of local development.
VALUE CREATION
FOR STAKEHOLDERS AND SHAREHOLDERS
A S Y S T E M I C A P P R O A C H T O WA R D S E F F I C I E N C Y, R E S I L I E N C E A N D G R O W T H
OPERATIONAL
EXCELLENCE
Low cash neutrality
Low time to market
High value reserves
CARBON NEUTRALITY
IN THE LONG TERM
PROMOTION
OF LOCAL DEVELOPMENT
Energy mix
Circular economy
Carbon offset
Dual flag approach
T
E
C
H
N
O
L
O
GICAL INNOVATION & DIGITALIZATION
Production for domestic market
Access to electricity
Economic diversification
Access to water and hygiene
Health and education
Public-private partnerships
Job creation
Know-how
and expertise transfer
Efficiency and integration are the strategic drivers leading Eni’s
business towards operational excellence.
This allows the achievement of low cash neutrality, a low
time-to-market and a high value resource portfolio, resilient also
in low carbon scenario.
The excellence of the operating model is also characterized by a
steady commitment to minimize risks and create opportunities all
along the value chain through the valorization of human resources,
the safeguard of health and safety, the environmental protection,
respect and promotion of human rights and focus on transparency
and anti-corruption.
Secondly, Eni’s business model envisages a path to decarbonisation
with the ambition to lead the Company to become carbon neutral
in the long term, aiming at maximize efficiency and reduce direct
emissions through the compensation of residual emissions,
promoting an energy mix with a low carbon impact.
In the long term, Eni supports a change of energy paradigm and
a conversion of the current consumption pattern towards a more
sustainable and rational one, leveraging on the principles of circular
economy, pursuing a path to conversion by exploiting the group’s
expertise and positioning in the downstream business.
Promotion of local development in Eni’s Countries of activities
is the third lever of the business model.
First of all, we supply our gas production to the local market,
expanding access to electricity and by promoting a large portfolio
of initiatives addressed to local communities: from local economies
diversification, to projects for health, education, access to water
and hygiene.
This “Dual Flag” approach leverages on the collaboration with
institutions, cooperation agencies and local stakeholders in order to
identify actions to satisfy the needs of communities in accordance
with the national development plans and the 2030 UN Agenda.
Eni is also committed to create job opportunities and transfer
its know-how and expertise to the local partners.
RESPONSIBLE AND SUSTAINABLE APPROACH
The responsible and sustainable approach represents for Eni
the logic for creating value in the medium and long term for the
company and all stakeholders, combining financial solidity
with social and environmental sustainability. This approach is
fundamental to operate in the complex current context
and respond to the crucial challenge of the energy sector:
the transition to a low carbon future and access to energy
resources for a growing world population. The 17 Sustainable
Development Goals (SDGs) of Agenda 2030, promoted by the
United Nations, are a reference framework for Eni, to guide
activities and seize new business opportunities, also in
partnership with various national and international organizations
to share knowledge and resources and contribute to the
achievement of development goals.
I
L
A
N
O
T
A
R
E
P
O
L
E
D
O
M
E
C
N
E
L
L
E
C
X
E
PEOPLE
SAFETY
COMMITMENT
PERFORMANCE
SDGs
Eni focuses on the growth,
enhancement and training
of its people, recognizing diversity
as a resource
• 31,701 employees at year end
• 23.3% women
• Over 1 million of training hours
(+5% vs. 2017)
Eni considers safety in the workplace
an essential value to be shared
between employees, contractors
and local communities
• TRIR 0.35
• TRIR down by 51% vs. 2014
ENVIRONMENTAL
IMPACT
REDUCTION
Eni promotes the efficient use
of natural resources and the
safeguard of protected areas that
are relevant to biodiversity,
identifying potential impacts
and mitigation actions
• 87% of freshwater reused
• -2% of freshwater withdrawals vs. 2017
• Recovered waste equal to 40% of disposed
waste from production activities
• -20% operational oil spills vs. 2017
• 60% of reinjected production water
HUMAN RIGHTS
Eni is committed to respect human
rights in its operations and to
promote their respect towards
partners and stakeholders
• Published Eni’s Statement on respect
for human rights
• 91% of employees trained on human rights
• 90% of security contracts containing clauses
on human rights
• 100% of new suppliers screened using social criteria
TRANSPARENCY
AND
ANTI-CORRUPTION
Eni carries out its business
activities with loyalty, fairness,
transparency, honesty and integrity
and in compliance with the laws
• Membership of EITI(a) since 2015
• 8 Countries where Eni supports EITI’s local
Multi Stakeholder Groups
• 32 audit actions on risk of corruption
activities
COMBATING
CLIMATE
CHANGE
Eni has defined a clear
decarbonization strategy
developing short, medium
and long term actions to promote
the energy transition
O
T
H
T
A
P
I
I
N
O
T
A
Z
N
O
B
R
A
C
E
D
LOCAL
DEVELOPMENT
THROUGH
PUBLIC-PRIVATE
PARTNERSHIP
To support local development,
Eni promotes access to energy,
economic diversification, education
and training, access to water
and hygiene, health also through
public-private partnerships
L
A
C
O
L
F
O
N
O
T
O
M
O
R
P
I
:
T
N
E
M
P
O
L
E
V
E
D
I
L
E
D
O
M
N
O
T
A
R
E
P
O
O
C
• -20% of GHG emission intensity index
(upstream) vs. 2014
• -16% of volumes of hydrocarbons sent
to flaring vs. 2014
• -66% upstream methane fugitive
emissions vs. 2014
• Net zero carbon footprint on direct emissions
of upstream activities (in equity) at 2030
• €94.8 million on community investment
in 2018
• Partnerships signed with UNDP and FAO
TECHNOLOGICAL
INNOVATION
Eni invests in new solutions
that can increase the efficiency
and sustainability of activities,
reducing costs and environmental
impact
• €197 million invested for research
and technological development
(+7% vs. 2017)
• 43 first patent filing applications of which
13 filed on renewable sources
(a) Extractive Industries Transparency Initiative: Global initiative to promote a responsible and transparent use of financial resources generated in the mining sector.
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 2018 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.
THE GLOBAL 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.
LETTER
TO SHAREHOLDERS
7
EMMA MARCEGAGLIA
Chairman
CLAUDIO DESCALZI
Chief Executive Officer
and General Manager
In 2018, Eni made outstanding progress both at optimizing the existing
asset portfolio and at strengthening it for the future.
These results owed to the process of transformation of our business model
started in 2014 in anticipation of the oil downturn, at the end of which
Eni has become more financially sustainable and resilient to the volatile
scenario as it has never been in the past.
Several drivers have underpinned our transformation: a track record of exploration successes coupled with the dual
exploration strategy which allowed us to early monetize discoveries, the optimization of the time-to-market of hydrocarbon
reserves, the operational efficiency, the restructuring of our downstream businesses aimed at reducing the breakeven and
financial discipline in investment decisions. Synergies within our businesses have been optimized and our commitment at
empowering local communities and at preserving the environment has become a driver of our business model.
At the core of our progress are our intangible assets: technologies, skills and know-how.
Leveraging on these drivers, we have built a new Eni based on efficiency, integration, deployment of new technologies
and an optimized asset portfolio. With a view to the future we strengthened and geographically diversified our upstream
portfolio, expanding our growth prospects with the building of a significant presence in the Middle East, while keeping
costs low and maintaining a high level of profitability by means of the creation of a strategic equity-accounted joint
venture with the ADNOC oil State company in Abu Dhabi.
In these years, we have consistently delivered on strategy guidelines leading to excellent results in terms of growth, returns
and a healthy balance sheet: 2018 marked a record in hydrocarbon production at 1.85 million boe/d, the cash neutrality
for funding capex and the floor dividend lowered to 52 $/bbl, which compares well to the 2014 baseline of 114 $/bbl, net
borrowings declined to €8.3 billion, with a leverage at 0.16, the lowest level of the last twelve years and among the best of the
industry, after having paid a total of €16.2 billion of dividends in the last five years in a challenging oil scenario.
In these years, exploration was at the core of our growth and cash generation. For the fourth consecutive year, Eni has
been nominated best exploration company in the oil business. This demonstrates the excellence of our discoveries
and the effectiveness of the dual exploration model, whereby Eni has elected to acquire high working interest in
exploration leases to achieve fast monetization of the discovered resources through the dilution of participation
interests, while retaining operatorship.
Since 2013, the dual exploration model allowed us to cash in approximately $10 billion mainly by diluting Eni’s interest
in the giant gas projects Zohr in Egypt and Area 4 in Mozambique. Leveraging the dual exploration model, a number of
strategic partnerships have been signed as well as the agreements signed in March 2018 to divest a 10% interest in
the Zohr field and the concurrent acquisition of interests in the producing concession agreements Lower Zakum (5%)
and Umm Shaif and Nasr (10%) located offshore the United Arab Emirates (UAE).
8
In the last five years, we have discovered some 5 billion boe of resources, of which 620 million in 2018 at competitive
costs, replacing more than 130% of our cumulative production with proved reserves.
Growth has been driven by a strengthened Exploration & Production portfolio. We aimed at diversifying our
geographical footprint by building a strong presence in the Middle East through strategic alliances such as the one in
Abu Dhabi, which was complemented with the assignment to Eni of a 25% interest in the offshore Ghasha concession,
a huge gas project where we were appointed technical operator with expected start-up by the end of the plan period
and a production target of 1.5 bcf/d.
We enhanced the producing platform in Norway, by merging our subsidiary Eni Norge with Point Resources, and
setting up the joint venture Vår Energi (Eni’s interest 69.6%), an independent company, leader in the upstream
segment in Norway. Hydrocarbon production is expected to target 250 kboe/d in 2023.
The reloading of the exploration asset portfolio was made with the objective of expanding the geographic reach of
our operations, targeting material assets with high working interests located in strategic areas. In the Middle East we
acquired seven high-potential, low-risk exploration leases totaling approximately 70 thousand square kilometers of
new acreage, notably in Abu Dhabi we were awarded Blocks 1/2 in the offshore area, promising synergies with the
project in Ghasha, onshore Oman with the signing of an EPSA on the Block 47, in the Sharjah Emirate with the entry in
three onshore blocks and in Bahrain, with the acquisition of Block 1, located in an offshore unexplored basin.
In 2018, we acquired other exploration assets of great interest in Lebanon, Mexico, Alaska, Morocco, Indonesia
and Mozambique where Eni was awarded mineral interests on an offshore area of 5 thousand square kilometers
balancing these acquisitions with the swap of exploration licenses in Mexico with Lukoil (farm-in of 40% interest
in Area 12 PSC) and the dilution of the interest in the exploration block located offshore Nour in Egypt (45% to
BP/Mubadala).
In 2018, hydrocarbon production set a new record at 1.85 million boe/d (up by 2.5% vs. 2017 at constant prices)
thanks to the five scheduled start-ups for the year – Wafa compression and Bahr Essalam phase 2 in Libya, OCTP
gas phase in Ghana and Ochigufu and Vandumbu in Angola –, the highest plateau on record in Iraq and, above all, the
extraordinary success in the ramp-up of Zohr field where we reached the first production target to more than 2.1 bcf/d,
nine months ahead the schedule and we revised the target to 3.2 bcf/d. Overall, in the year start-ups and ramp-ups of
fields started up in 2017 added approximately 300 kboe/d to the full year plateau.
Future production growth will be fuelled by the six FIDs made in the year related to projects in Area 1 in Mexico
targeting the development of 2.1 billion of boe in place, Merakes in Indonesia, in synergy with the Jangkrik producing
field, Cassiopea in Italy, Baltim South West in Egypt, Nenè phase 2 in Congo and Cabaca in Angola.
Finally, relevant progress was made towards the FID on the first phase of the giant Rovuma LNG project, which
includes the design and construction of two trains for the liquefaction of natural gas with a capacity of 7.6 million
tonnes of LNG each, thanks to the LNG long-term purchase commitments obtained by the partners of Area 4.
Results obtained in the development activity leveraged on our strategy of reducing the time-to-market of the reserves
based on the parallelization of different stages of the project (exploration, pre-fid activity and construction), control of
the project risks through the insourcing of critical phases (such as detailed engineering, construction supervision and
commissioning) as well as applying a phased approach which allow to reduce idle capital and financial debt.
We replaced with new organic proved reserves the 100% of the production thanks to new discoveries and progress in
maturing reserves. On an all sources base, the RRR stood at 124%, while the three-year average organic RRR reached
131%. At year end, total proved reserves amounted to 7.2 billion of boe, with a life index of 11 years.
Our leadership in the exploration, the reduction in time-to-market, the effectiveness of the phase-development activity
and opex control contributed to reduce Eni’s development projects breakeven overall at $25/boe.
In 2018, adjusted operating profit of the E&P segment was €10.85 billion, more than doubling y-o-y, with a Brent price
increasing by 31%. A larger portion of more valuable barrels boosted the cash flow per barrel to $22.5, well ahead of
our guidance set for 2022.
The downstream businesses reported robust results driven by the finalization of the turnaround implemented in these
five years, which made these businesses sustainable also in an unfavorable environment.
The Gas & Power segment reported an adjusted operating profit of €0.54 billion, more than doubling 2017 results and
significantly better than the announced guidance. This performance was due to the restructuring the portfolio of long-
term gas contracts, leveraging on the associated flexibilities to capture scenario upsides, the optimizations in the power
business, trading and logistics as well as the growth in the LNG business with 8.8 MTPA of contracted volumes (up by 70%
compared to 2017). All along the value chain we leveraged on the integration with the upstream segment contributing to
the acceleration of FIDs at gas reserves development projects. The retail business performed strongly, driven by value
creation at the European customer portfolio which reached 9.2 million clients, efficiency gains from the operations,
digitalization programs and automatization of post-selling activities and working capital monitoring.
In the oil downstream, technological innovation was the driver of the turnaround, which allowed Eni to revamp certain
unprofitable plants, thus reducing the exposure to the volatility of the oil feedstock. Today we are proud to announce the
LETTER TO SHAREHOLDERS 9
start of a new growth phase in our refining business. The strategic acquisition of a 20% interest in the Ruwais refinery
in Abu Dhabi for a consideration of $3.3 billion gives us the possibility to deal with one of the better opportunity to
expand our presence in the market in terms of efficiency and profitability. This acquisition will allow us to increase
by approximately 35% our refinery capacity and to significantly improve the profitability outlook by reducing the
breakeven margin from 3 $/bbl to 2.7 $/bbl by 2020 and till to 1.5 $/bbl by completing the refinery upgrading, with a
conversion capacity of 1.1 million bbl/d at 2023.
Further value will be extracted by the set-up of a trading joint venture in partnership with the partners of the refinery,
aiming at catching marketing opportunities in Europe, the Middle and Far East and Africa.
In 2018, on the back of an unfavorable scenario, the Refining & Marketing reported an adjusted operating profit of
€390 million and a surplus of cash flow after funding capex for the year, thanks to excellent results of the marketing
activity, the contribution of margins of green throughputs and optimization actions and feedstock flexibility.
Also in Versalis the technological driver was the engine of the value creation with the development of the green
chemical business and specialties, by reducing the incidence of plastic commodities in the Company’s portfolio, which
are subject to the volatility of the oil cycle. In line with this strategic guideline, in 2018 a new production unit of high
range of elastomers EPDM for the automotive industry was started up.
Furthermore, was finalized the acquisition of the activities of the Mossi & Ghisolfi Group, focused on biochemical
technologies and processes based on the use of renewable sources from biomasses and the establishment of a joint
venture with Mazrui Energy Services in the Middle East to market specialties based on Versalis’ technology for the
Oil & Gas industry. In 2018, in a particularly unfavourable petrochemical scenario, Versalis targeted the breakeven in
profitability, leveraging on business’ restructuring.
Integration is on the base of the renewable segment development. This is managed by the New Energy Solutions
division which in 2018 completed and started up three photovoltaic plants (Assemini in Sardinia, a unit in Gela and
one in the Green Data Center) among the “Italia Project” which includes certain initiatives aimed to create sustainable
value in the reclaimed industrial areas, mainly in the Southern region of Italy.
Outside Italy, we started up a solar plant in Algeria with a capacity of 10 MW at the Bir Rebaa North oil field, jointly
operated by Eni and Sonatrach, which will make the upstream activity energy self-sufficient. Furthermore, we started
the project to build a 50 MW wind farm at Badamsha in Kazakhstan, to supply renewable energy to the Country.
Our businesses growth is even more focused on the long-term sustainability. Climate change is a pillar of our industrial
strategies and is also factored in the evaluation of our projects which have to be sustainable also in a low carbon scenario.
Progress achieved so far in the evolution of our business model is based on a clear decarbonization strategy focused on a
constant commitment to achieving increasing operational efficiency and finding innovative and technological solutions to
foster energy transition and reduce emissions, thus also leveraging projects of circular economy and carbon offset.
In 2018, we achieved significant results on E&P GHG emission intensity index reporting 21.44 tCO2eq/kboe, a 20%
reduction compared to the baseline 2014 and in line with the target at 2025 declared to the market, a 43% reduction.
Also the downstream business turnaround is a founding part of this long-term growth strategy. It is based on
the “green” conversion of the least competitive sites, extending their life in low carbon optics, through the use of
renewable feedstock and raw materials such as food waste, urban waste and secondary, alternative commodities to
the traditional feedstocks and in line with the principles of the circular economy.
In order to optimize resources all along the life cycle, Eni has launched eco-design projects. We are also engaged in
developing technologies for the chemical-physical and mechanical recycling of polymers at the end of use, such as
the reuse of expanded polystyrene for thermal insulation. These projects leverage both on internal research and on
partnership and collaboration with associations/consortia. Broad partnerships have been established with Pertamina,
the state oil company of Indonesia, and in Italy with Coldiretti for large-scale applications of the Eni’s technologies for
the enhancement of biomasses and waste.
At the heart of our values is the commitment to promote and improve access to energy mainly in Africa according to
the “dual flag” business model, such as the OCTP project in Ghana providing the supply of the gas equity produced by
our investment in the Country, contributing to the local socio-economic development.
Our future plans in Africa will be supported and developed by leveraging on the prestigious collaboration with UNDP
(United Nations Development Programme). In September 2018, Eni and UNDP signed a partnership to improve access
to sustainable energy in Africa and to contribute to accomplishing the United Nations Sustainable Development Goals
(SDGs). The first phase of the cooperation will involve ten African Countries in order to promote sustainable energy
contributing to the achievement of four of the SDGs of the United Nations, in particular the number 7 on accessible and
clean energy. This partnership is the first signed between the UNDP and a global energy company, and underpins the
credibility of our strategies.
Finally, our performance on safety continued on its track record of results within the industry’s low average range, with
a Total Recordable Injury Rate (TRIR) of 0.35 in 2018.
Our financial results for 2018 were excellent. Adjusted operating profit was €11.24 billion and adjusted net profit €4.58 billion,
LETTER TO SHAREHOLDERSEni Annual Report 2018 10
both almost doubled compared to 2017, supported by a better trading environment with Brent prices increasing by 31% ,
which showed the ability of our business model to create extra-value in a favorable market scenario.
The drivers of these results were the robust performance of the E&P segment (up by 110%) and the recovery in the
G&P (up by 154%). Also the downstream oil and chemical businesses reported a positive contribution notwithstanding
a challenging trading environment. At the Brent price scenario of 71 $/barrel, in 2018 cash flow from operations was
€13.45 billion. Other positive cash flows were associated with positive changes in receivables and payables associated
with investing activities (mainly including the cash-in of the deferred price of the Zohr disposals made in 2017), which
amounted to €0.9 billion. These inflows funded the reassessed amount of capital expenditures of €7.94 billion and the
dividend of €2.95 billion, leaving a surplus of around €3.5 billion.
Consequently, on the basis of the Group’s cash flow sensitivity to the Brent scenario which assumes a change of
approximately €0.19 billion in cash flow for each one-US dollar change in the Brent price, the cash neutrality for
funding the capital expenditure for the year and the floor dividend would have been achieved at 52 $/barrel. This is
re-determined in 55 $/barrel when excluding from cash inflows the deferred tranches of the consideration on the
disposal of Eni’s interests in Zohr made in 2017 (€450 million), being this the unique non-organic components of the
cash flow. Net borrowings reduced to €8.3 billion with a leverage of 16%, seven percentage points lower than in 2017;
return on average capital employed almost doubled to 8.5% (compared to 4.7%).
STRATEGIES AND TARGETS
Considering a volatile trading environment, we will retain a financially-disciplined approach to capital spending. At
the long-term Brent scenario of 70 $/barrel, in the next four years we plan to invest approximately €33 billion, a
slight increase compared to the previous plan. Approximately 80% is allocated to the exploration and production of
hydrocarbon reserves. 9% of group capex will be devoted to growing the green business, in particular by increasing
the installed capacity to generate power from renewables, decarbonization projects and circular economy initiatives
designed to produce advanced biofuels, renewable chemicals and new products from waste and biomasses as well as
to extend the useful life of abandoned and decommissioned industrial sites.
The strategic guidelines of the E&P segment are to monetize and enhance the exploration portfolio and to maximize
cash generation driven by production growth.
We forecast to grow production organically at an annual average rate of 3.5% till 2022, to reach a plateau of 2.13
million boe/d. New projects start-ups and the ramp-ups of producing fields will contribute about 660 thousand boe per
day in 2022.
New projects are geographically well balanced: Mexico with the start-up of Area 1, Indonesia with Merakes, Italy,
upgradings/new phases of producing areas in Egypt, Algeria, Congo and Angola, initiatives in Norway and, at the end of
the plan period, the start-ups of giant gas projects such as Coral in Mozambique and the first development of Ghasha
in the UAE. The visibility of our production target is excellent because the expected increases are tied to the ramp-up of
several operated fields which are currently performing, and the projects sanctioned in 2018.
The other drivers of cash generation will be integration with G&P to extract value from the equity gas, strict control on drilling
and field operations risks and asset integrity with a view of minimizing production losses due to unplanned downtime.
In exploration we intend to adopt a disciplined approach with planned capex of $0.9 billion/year relating to initiatives in
frontiers areas or in high-equity, conventional basins also looking for a possible deployment of our dual exploration model,
as well as initiatives in proven and near field areas with short time-to-market to contribute rapidly to production increases
and cash flow. Our exploration campaign will be focused offshore Mexico, in the Middle East and in mature and high
potential areas close to existing facilities in Norway, Angola, Ghana and Egypt. We expect to discover 2.5 billion boe in the
plan period at the unit cost of below $2/barrel, contributing to expand the geographical reach of our operations.
In the Gas & Power segment we confirm the structural sustainability in the plan period and we expect a significant
contribution to cash generation notwithstanding a challenging trading environment, characterized by the continuing
pressure on gas and power spreads. The main driver will be the enhanced synergies with all Eni’s businesses in order to
optimize the trading of oil and products to capture market upsides, as well as to develop the LNG portfolio by increasing
contracted volumes from 8.8 MTPA in 2018 to 14 MTPA by 2022 and 16 MTPA by 2025, capitalizing on equity gas and
maximizing margins all along the value chain. Long-term gas contracts will be de-risked and continuously renegotiated with
suppliers to align prices at market conditions. In the retail business we will deliver a robust profitability leveraging on the
development and full monetization of the customer portfolio, which will be increased to reach 12 million customers. Growth
will also be pursued through focused and synergic acquisitions, while margin expansion will leverage on the contribution
of extra-commodity products and services and continuous focus on efficiency. We reaffirm the G&P financial targets of an
adjusted operating profit of €0.7 billion in 2022 and a cumulative organic free cash flow of €2.3 billion over the plan.
In the R&M business we intend to target the breakeven margin of 3 $/bbl at our legacy refineries, with full operability
of our refineries, by maximizing plant reliability, optimizing setup and supply and by increasing the licensing of
proprietary technologies.
LETTER TO SHAREHOLDERS 11
The integration of Eni’s 20% interest in ADNOC Refining will leverage on technological synergies and will allow to halve
the breakeven margin to 1.5 $/bbl by delivering on the identified projects for plant upgrading.
The bio-refining segment is expected to grow thanks to the start-up and full operation of the Gela plant and the
upgrading of Venice. Our green diesel production will grow to 1 million tonnes per year by 2021.
In the Marketing activity we target robust results fuelled by quality and innnovation in our services, the contribution of
premium products’ margins and the development of the non-oil segment and the sustainable mobility.
Versalis’ strategy is focused to make the business more resilient to the volatility of the trading environment by shifting
the product portfolio towards high-value specialties and green chemicals, by using proprietary technologies to sustain
margin expansion and international growth, and by executing a number of optimization initiatives such as better
vertical integration, increasing feedstock flexibility and reduction in variable production costs.
In addition, these initiatives will contribute to the accomplishment of the Company’s targets on the development of the
circular economy and decarbonization.
In addition to the already stated target of 43% reduction compared to the 2014 baseline of the upstream intensity
emission rate by 2015 through zero gas flaring projects and methane fugitive emissions (the 80% reduction
target compared to the 2014 baseline by 2025), we intend to achieve zero net carbon footprint in our upstream
business by 2030. We will do this by increasing efficiency to minimize direct upstream CO2 emissions, maximizing
decarbonization initiatives and developing forestry initiatives offsetting residual upstream emissions, while
providing benefits to local communities.
The identified strategic guidelines include also the acceleration in growing low carbon sources such as gas and
bio-fuels and the development of power generation capacity from renewable sources (solar photovoltaic, wind and
other) leveraging on synergies with Eni's business up to 1.6 GW of installed capacity to 2022 and 5 GW to 2025,
with the ambition to reach more than 10 GW at 2030.
Another lever of our strategy is the development of circular economy initiatives aiming to exploiting waste and
biomasses to extract new energy, new products or materials and give new life to decommissioned or reclaimed
assets. On these activities, Eni intends to invest more than €950 million ranging from the recovery of biomasses
and waste, to the recycling of polymers and processes of eco-design, up to the extension of the useful life of the
assets and products from a low carbon side. Further €220 million will be addressed to research and development
as well as to technological innovation.
On these bases and given the constant reduction of breakeven of new development projects, we believe that our
portfolio will be resilient also under severe decarbonization scenarios. Another driver of our sustainability is the
empowerment of the communities in the Countries where we operate, in line with our dual flag approach and
consistently with the national Development Plans on the 2030 Agenda of the United Nations.
All in all, while being aware of the magnitude of our efforts during the downturn in terms of growth, efficiency and
sustainability, we intend to make even more robust Eni’s competitive position and its resilience to the oil scenario.
We will accomplish this by leveraging on asset portfolio which is geographically better diversified and more balanced
along the entire hydrocarbon value chain and on the planned initiatives from now to the first half of the next decade.
Our medium-term objectives are to reduce the cash neutrality to 50 $/barrel, to ensure a growing remuneration to
shareholders and to enhance the Company’s contribution to the achievement of the SDGs of the United Nations.
We are extremely proud of the global Eni team. Without the women and men of Eni, we would not have been able to
transform the business over the past five years to drive the Company to those achievements.
On the basis of 2018 results, we will propose the payment of a dividend of €0.83 per share, of which €0.42 already
paid, at the Annual Shareholders meeting to be held on 14 May. Our strong outlook underpins our progressive
shareholder remuneration that envisage, for 2019, a 3.6% dividend increase to €0.86 per share and the start of a
four-year buyback programme with an initial capital allocation of €400 million in 2019. In the following three years,
assuming a leverage steadily below 20%, the annual capital allocation will amount either to €400 million in a $60-65
per barrel Brent scenario or €800 million with a Brent scenario above $65 per barrel.
March 14, 2019
In representation of the Board of Directors
Emma Marcegaglia
Chairman
Claudio Descalzi
Chief Executive Officer and General Manager
LETTER TO SHAREHOLDERSEni Annual Report 2018 12
ENI AT A GLANCE
2018: year of outstanding financial and industrial results achieved thanks to the fast
implementation of our strategy.
2018 results were driven by our successful exploration activity supported by the “dual exploration” strategy allowing Eni to early
monetize discoveries, to achieve efficiency through the optimization of hydrocarbon reserves time-to-market, the breakeven decrease in
downstream businesses and the financial discipline on spending.
The optimization of existing portfolio, the geographical diversification strategy and the improved balance of assets portfolio along the
value chain through a robust growth in the Middle East, together with our commitment in promoting local development, in environmental
protection and in fostering Eni’s expertise and technologies enabled Eni to seize synergies and growth opportunities.
Public-private partnerships started-up in 2018 will enable us to share resources, know-how and expertise with the United Nations
Development Programme (UNDP) for sustainable development and to aim at achieving SDGs, in particular the universal access to energy
by 2030, the actions to combat climate changes and the protection, restoration and sustainable use of the earth’s ecosystem and with the
Food and Agricultural Organization (FAO) for clean and safe water access in Nigeria.
€11.24 BLN
up by 94% vs. 2017
€13.45 BLN
up by 35% vs. 2017
GROUP ADJUSTED OPERATING
PROFIT
ADJUSTED NET CASH FLOW
FROM OPERATIONS
€8.29 BLN
down by 24% vs. 2017
NET BORROWINGS
BRENT DATED ($/barrel)
2018
2017
2016
71.04
54.27
43.69
SERM ($/barrel)
2018
2017
2016
3.7
5.0
4.2
AVERAGE EUR/USD EXCHANGE RATE
2018
2017
2016
1.181
1.130
1.107
PSV vs. TTF (€/kmc)
2018
2017
2016
17
28
20
The outstanding financial results of the year were achieved against a backdrop of highly volatile Brent prices, due to signs of weakening global growth, oversupply,
uncertainty tied to the commercial dispute between the USA and China, the Brexit, as well as geopolitical issues.
ENI GROUP
Operating profit (loss)
Adjusted operating profit (loss)
Net cash from operations
TRIR (Total recordable
injury rate)
Leverage
2018
2017
2016
(€ million) 9,983
8,012
2,157 ▲ +25%
-6% vs. 2017
(total recordable injuries/
worked hours) x 1,000,000
11,240
5,803
2,315 ▲ +94%
13,647 10,117
7,673 ▲ +35%
0.35
0.16
0.33
0.35 ▼ +6%
0.23
0.28 ▲ -0.07
UPSTREAM GHG INTENSITY INDEX
0.35 TRIR
AMONG THE LOWEST LEVEL
COMPARED TO THE AVERAGE
OF THE INDUSTRY
2018 SOURCES AND USES (€ bln)
ORGANIC CASH FLOW VS. NET BORROWINGS
(€ bln)
€3.8 bln
cash flow
disposals
surplus
capex
dividends
acquisitions
7
6
5
4
3
2
+123%
-40%
2014
2018
net borrowings
organic cash flow
14
13
12
11
10
9
8
0.16 leverage
THE LOWEST LEVEL
IN THE LAST 12 YEARS
52$/barrel
2018 CASH NEUTRALITY
13
EXPLORATION & PRODUCTION
2018
2017
2016
Adjusted operating profit (loss)
(€ million) 10,850
5,173
2,494
Hydrocarbon production
(kboe/d)
1,851
1,816
1,759
Opex per boe
Profit per boe
($/boe)
6.8
9.3
6.6
8.7
6.2
2.0
GHG emissions/100% operated
hydrocarbon gross production
(mmtonnes CO2eq/kboe)
21.44
22.75
23.56
1.85
million boe/d
NEW RECORD IN HYDROCARBON
PRODUCTION
+110% vs. 2017
UPSTREAM PROFITABILITY
GAS & POWER
Adjusted operating profit (loss)
(€ million)
2018
543
2017
214
2016
(390)
Worldwide gas sales
LNG sales
GHG emissions/kWheq (EniPower)
(gCO2eq/kWheq)
Retail customers in Italy
(million)
(bcm)
76.71
80.83
86.31
10.3
402
7.74
8.3
395
7.65
8.1
398
7.68
+154% vs. 2017
G&P PROFITABILITY
REFINING & MARKETING AND CHEMICALS
Adjusted operating profit (loss)
(€ million)
2018
380
2017
991
2016
583
Retail sales of petroleum products in Europe
(mmtonnes)
8.39
8.54
8.59
Refinery throughputs on own account
23.23
24.02
24.52
€380 MLN
R&M and Chemicals
GHG emissions/products (crude oil and
semifinished) processed in refineries
(tonnes CO2eq/kt)
253
258
278
ADJUSTED OPERATING PROFIT
Sales of petrochemical products
(ktonnes)
4,938
4,646
4,745
Thanks to the deep transformation process started in 2014, Eni today, after years of oil market downturn, owns a sustainable financial
structure and is resilient to the volatility of scenario as never before. Through the strict implementation of our strategic guidelines Eni was
able to combine growth, profitability and soundness of financial position, achieving record hydrocarbon production at 1.85 million boe/d in
2018, reducing net borrowings to €8.3 billion, with a leverage of 0.16, the lowest level in the last 12 years, among the best in the industry,
thus distributing €16.2 billion of dividend in last five years, on the backdrop of a challenging trading environment.
PRODUCTION VS. CAPEX
(mmboe/d)
1.90
1.80
1.70
1.60
FINANCIAL SOUNDNESS
DIVIDENDS PAID
18
12
6
(€ bln)
14
10
6
2
4
1
0
2
5
1
0
2
6
1
0
2
7
1
0
2
8
1
0
2
30
20
10
€16.2 billion
in the last 5 years
2014
2015
2016
2017
2018
production (mmboe/d)
capex (€ bln)
net borrowings (€ bln)
leverage (%)
2014
2017
2015
2018
2016
ENI AT A GLANCEEni Annual Report 2018 14
STAKEHOLDERS
ENGAGEMENT
Our stakeholders are first and foremost people who live in the areas where Eni works: their knowledge and sharing of their concerns
and expectations are the basis of our commitment to build lasting relationships in order to contribute, together, to a sustainable
development. The direct involvement of stakeholders in each phase of the activities, the promotion and sharing of common principles
and dialogue are at the basis of the creation of long-term value. Eni is present in 67 Countries, characterized by social, economic
and cultural contexts, which may also be very different from one another: in carrying out the activities, the daily and proactive dialogue,
in place with different stakeholders, is essential in order to establish a solid and transparent relationship of trust, which can be
a promoter for shared development processes.
For this reason, Eni has set up an IT platform called the Stakeholder Management System (SMS) dedicated to support the management of the
complex network of relationships in the territories, monitoring the expectations of the populations and the results of development projects.
Topics arisen from the dialogue with stakeholders
15
This tool allows to survey and visualize, through a map, the relations with each category of stakeholder, highlighting any areas for improvement,
with the possibility of better investigating the potential impacts on human rights, tracing the presence of vulnerable groups and the presence of
areas of naturalistic and/or cultural value around the areas of activity, enabling a more conscious management of the operational realities.
Main stakeholder engagement activities during the year
PU
ENI’S PEOPLE AND NATIONAL
AND INTERNATIONAL
LABOUR UNIONS
LC
LOCAL COMMUNITIES
& COMMUNITY
BASED ORGANIZATIONS
SP
CONTRACTORS,
SUPPLIERS AND
COMMERCIAL PARTNERS
˛ Internal communication plan focused on
strategy, targets, Eni’s results through
events and meetings on strategic issues
˛ Integrating skills and experiences
(best practices sharing, storytelling,
support to organization and communication
of defined initiatives)
˛ Sample climate analysis
˛ Meeting with national and international
labour unions, in the field of Global
Framework Agreement, finalized to a
dialogue on certain social and working
situations in Countries of worker
representatives’ origin
˛ Involvement of over 200 communities
in the territories in which Eni operates
˛ Consultation activities with authorities
and local communities for new exploration
activities or for the development of new
projects
˛ Collaboration with the authorities and
the local communities for planning,
management and realization of initiatives
for the community (Congo: CATREP(a) project;
Mozambique: educational and agro-livestock
development projects; Ghana: Livelihood
Restoration Plan and water access project;
Iraq: educational projects)
˛ Involvement of suppliers with Human
Rights Assessment
˛ Communication, feedback and improvement
plans
˛ Sharing the draft of the Supplier Code of
Conduct on Eni’s values of sustainability
˛ Participation in the IPIECA(b) WG: Forum
on Oil & Gas Sustainability best practices
˛ Green sourcing project: identification
of the levers in the supply chain for the
reduction of environmental impacts
FC
FINANCIAL
COMMUNITY
CC
CUSTOMERS
AND CONSUMERS
˛ Launch of the 2018 strategic plan in London,
Milan and New York
˛ Road-show of top management and
of the President on governance issues
˛ Conference call on quarterly results
˛ Participation of top management in
thematic conferences organized by financial
institutions
˛ Engagement with investors about industrial
topics, financial and ESG themes also
relating to Shareholders’ Annual meetings
UR
UNIVERSITIES AND
RESEARCH CENTRES
˛ Meetings with representatives of
Universities, Research Centers and third-
party companies with which Eni collaborates
or interfaces for the development of
innovative technologies concerning the
topics of greatest interest
˛ Collaborations with institutions with which
Eni has a framework agreement, such as the
Polytechnic of Milan and Turin, University of
Bologna, MIT, CNR, INSTM, ENEA and INGV(e)
˛ Collaborations for the development of impact
assessment models (Columbia University
and Milan Polytechnic)
˛ Meetings and workshops with Presidents
and managers of the energy sector of
national and local CA(c) on topics such as
sustainability, circular economy, reclamation
and environmental remediation
˛ Sponsorization of CA initiatives on the
issues of sustainability and the circular
economy to which Eni’s senior officials
have taken part, bearing witness to our
initiatives in this regard
˛ Territorial meetings organized with the
Customers’ Associations of the CNCU(d)
OA
VOLUNTARY
PARTECIPATION IN
ORGANIZATIONS AND
CATEGORY ASSOCIATIONS
˛ Membership and participation to OGCI, IPIECA,
WBCSD, UN Global Compact, CIDU, EITI(f)
˛ Collaboration with DIHR(g) and IHRB(h)
˛ Conventions, debates, seminars and training
initiatives on sustainability issues: creation
of guidelines and sharing of best practices
˛ Participation to associative organism
and specialized worktables
˛ Meetings with local business associations
on the supplier qualification process
II
DOMESTIC, EUROPEAN
AND INTERNATIONAL
INSTITUTIONS
˛ Meetings with local, national and
international political and institutional
members on energy and climate issues
˛ Active participation in technical-institutional
worktables, mixed commissions on energy
opportunities of dialogue promoted by
Government and the Italian Parliament
˛ Meetings with national and local institutional
delegations during State visits and at
industrial sites
CD
ORGANIZATIONS
FOR COOPERATION
AND DEVELOPMENT
˛ Promotion of public-private partnerships
to carry out projects in line with Country
development plans
˛ Sharing of internationally adopted policies
and methodologies
˛ Capacity building activities carried out
with institutions
a) Centre d’Appui Technique et de Ressources Professionnelles.
b) Oil & Gas Association active in environmental and social issues.
c) Consumers’ Association.
d) Italian National Council of Consumers and Users.
e) Massachusetts Institute of Technology; National Research Council
(Consiglio Nazionale delle Ricerche); National Interuniversity Consortium
for Materials Science and Technology (Consorzio Interuniversitario Nazionale
per la Scienza e Tecnologia dei Materiali); National agency for new technologies,
energy and sustainable economic development (Agenzia nazionale per le nuove
tecnologie, l’energia e lo sviluppo economico sostenibile); National Institute
of Geophysics and Volcanology (Istituto nazionale di geofisica e vulcanologia).
f) Oil and Gas Climate Initiative; World Business Council for Sustainable
Development; Comitato Interministeriale Diritti umani; Extractive Industries
Transparency Initiative.
g) The Danish Institute for Human Rights.
h) Institute for Human Rights and Business.
STAKEHOLDERS ENGAGEMENTEni Annual Report 2018
16
SCENARIO
AND STRATEGY
The reference market and the competitive environment
Transition towards a low carbon energy mix
Companies operating in the energy sector are facing with two
challenges: satisfy growing energy needs, guaranteeing everyone
an adeguate access to energy and limit their emissions in the
atmosphere, contributing to the gradual path to decarbonization, in
accordance with the decision taken in COP, starting from Paris 2015.
In 2040 worldwide population is expected to grow from 7.5
billion to 9 billion and the energy demand will increase by
approximately 30%. There will be also a geographical shift in
energy consumption and the additional total demand will come
from non-OECD Countries, representing in 2040 approximately
85% of worldwide population.
In this context, natural gas represents an opportunity for a
strategic repositioning of the oil companies thanks to lower
carbon intensity and the possible integration with renewable
sources in the electricity production. There is a growing
awareness on the needs to promote policies aimed at replacing
coal in electricity generation.
Recovery and volatility
2018 was characterized by a sharp increase in oil prices, supported
by production cuts of the OPEC and non-OPEC Countries, the
announcement of new sanctions to Iran and a robust growth in
demand. This trend was stopped at the end of the year when signs of
a new surplus emerged. The decline of exports from Iran, combined
with the Venezuelan crisis, pushed large producers to compensate
losses in the market. The record productions of USA, Russia and
Saudi Arabia generated a perception of oversupply. At the same time,
concern of a slowdown in demand increased, particularly in emerging
economies, while Trump urged lower prices in order to support US
consumers. The Brent price stands on an average of 71 $/barrel (up
by 17 $/barrel vs. 2017), with a decrease of 30% from October to
December, boosted by heavy speculative sales on future markets.
2019, not only OPEC
The decision of new cuts taken at the end of 2018, the geopolitical
losses in Iran and Venezuela and a slowed-down US growth, due to
logistics and financial constraints, contribute to ensure a measured
supply in 2019. Despite an expected declining economic growth, oil
demand is still expected robust. In the second half of the year, the
IMO which will be effective since January 2020 will require worldwide
ships to use lower sulphur fuels (0.5%) is expected to be a strong
discontinuity driver which could generate higher crude oil prices and
refining margins.
New challenges for refining industry
The refining industry has moved from significant overcapacity to a
rebalancing phase thanks to the rationalization and the closing of
plants in the 2009-2015 period.
The rationalization phase slowed down in 2016-2017 to stop in
2018. In 2018 and 2019 a new wave of refining capacity restarted,
particularly in Asia and the Middle East, with an impact on assets
in the less competitive regions, not only in Europe but particularly
in Latin America and Africa. In Europe, following the 2018 start-up
of the new refinery in Turkey, the capacity is expected to remain
stable. The IMO impact at 2020 will foster the profitability of
complex refineries in place of simple ones subject at risk of shut-
down. However, European refiners could be less penalized because
of already achieved capacity reduction.
New challenge for sustainability
The environmental, social and governance performance are
more crucial on the evaluation of a company, in particular large
companies are requested to contribute to the achievement of the
Sustainable Development Goals (SDGs) including access to energy
and contrast to climatic changes. Relating to the energy access
(SDG 7), IEA estimates that people without access to energy (now
estimated at 990 million) in 2030 will be still 650 million, with a
large part located in Africa, while those without access to clean
sources for cooking will be 2.2 billion (today 2.7 billion).
Facing with challenges of this magnitude, the achievement of the SDGs
requires an unprecedented cooperation between public and private
sectors, involving organizations representing both civil society and
businesses.
Particular responsibility in public-private partnerships (PPP) is
assigned to multinational companies, whose involvement, together
with different players as bilateral and multilateral governmental
institutions and NGOs, opens a new perspective relating to
operational effectiveness and allocation of the necessary
resources for financing development projects.
Respect of Human Rights is a relevant issue for companies, in
particular the gradual integration of the Guideline principles of
the United Nations for the Human Rights and Enterprise (UN
Guiding Principles on Business and Human Rights, 2011) in the
main company’s processes, which are supported at country
level by the National Action Plans on Corporations and Human
Rights and various legislative initiatives (i.e. laws against
modern forms of slavery in the United Kingdom, 2015 and
Australia, 2018).
17
Industrial Plan
In a strongly volatile scenario, Eni completed the deep transformation
process of its businesses, which allowed to continue to grow by
strengthening the financial structure. This transformation has been
successfully achieved thanks to the speed of action based on skills,
know-how and technologies, by placing at the heart of the strategy
the sustainability of Eni’s business model. Now, Eni is an integrated
and flexible company with all the businesses able to contribute to
long-term value creation.
The 2019-2022 plan gives a new input to growth and consolidates the integration of the sustainability
in the business model. The plan consists in the following strongly synergic strategic levers:
EFFICIENT
AND RESILIENT GROWTH
(operating model)
AMBITION TO
CARBON
NEUTRALITY
PROMOTION OF LOCAL
DEVELOPMENT
(cooperation model)
The efficient and resilient growth will be supported by a strategy
aimed at increasing integration of businesses, geographic
diversification of the activities and rebalancing of the upstream
vs. mid-downstream business through those actions already
taken or characterized by an advanced maturity level
and soundness.
The main planned actions are: replacement of resources through
exploration, start-up/ramp-up of producing fields or of new projects,
the sanctioning of projects to support medium and long-term growth,
the renegotiations of gas supply contracts, the development of
the global LNG portfolio, the enhancement and growth of gas and
power retail customers also through portfolio activities, the reduced
breakeven of refining activity and international development, the
integration and specialization of chemical business.
These actions will be pursued leveraging on the operating model
which assumes the continuous commitment to minimize risk and
the central role of human capital, environment and security.
The balanced development of activities portfolio will allow to contain
cash neutrality and maintain a solid financial structure.
Eni also pursues a strategy targeted to the long-term carbon neutrality
through a defined path that includes: (i) actions on energy mix and
maximization of energy efficiency and reduction of direct emissions;
(ii) development of forest conservation, reforestation or afforestation
projects to increase CO2 absorption capacity in the atmosphere, with
positive effects on local communities; (iii) development of circular
economy initiatives aiming at the valorization of waste and biomass
and the recovery of disused or reclaimed assets.
Eni, confirming its tradition, will also continue to promote local
development leveraging on the cooperation model (dual flag
approach), focused on supporting Countries in their social
and economic development, involving all the stakeholders.
Development will be reached by promoting access to electricity
and water, developing health, education and hygiene projects,
as well as know-how sharing.
Drivers of the integrated model for a sustainable growth will be the innovation and the spread
of digital technology which will allow to improve safety at the workplace and to catch new opportunities
of development and efficiency
SCENARIO AND STRATEGYEni Annual Report 2018 18
PRODUZIONE
IDROCARBURI
CAGR
RISORSE
ESPLORATIVE
COPERTURA
ORGANICA
DEGLI
INVESTIMENTI
€
FREE CASH
FLOW
CUMULATO
BREAKEVEN
COMPLESSIVO
NUOVI
PROGETTI
IN ESECUZIONE
+3,6 % 2018-2022
produzione organica
2.5 mld boe
nel quadriennio
<40 $/boe
nel quadriennio
~€22 mld
nel quadriennio
25 $/boe
Upstream
HYDROCARBON
PRODUCTION
CAGR
DISCOVERED
RESOURCES
ORGANIC
CAPEX CASH
NEUTRALITY
€
CUMULATED
FREE CASH
FLOW
TOTAL
BREAKEVEN
OF NEW
PROJECTS
IN EXECUTION
+3.5 %
2018-2022
organic production
2.5 bln boe
in the four-year plan
~37 $/boe
in the four-year plan
€22 bln
in the four-year plan
25 $/boe
Valorization and growth of the exploration portfolio, with
the target to discover 2.5 billion boe and contribute to the
geographical diversification.
● Exploration with operatorship on conventional assets and high-
equity according to the “Dual Exploration Model”.
2018-2022 period focusing on value, leveraging on the ramp-
ups at fields started up in 2018 and new planned production
in the next four years with a level of cash flow per boe higher
than the portfolio average and sustainable even at lower
Brent prices.
● Focus on near-field exploration with reduced time-to-market and
● Start-up and strengthening of integration with the Gas & Power
rapid cash flow in Countries with operated infrastructures.
● Build-up of exploration activities in “high risk-high reward” areas.
● Drilling of more than 140 wells located in more than 25
Countries.
Cash generation growth with a cumulative free cash flow
at €22 billion in the 2019-2022 period.
● Production growth at an average annual rate of 3.5% in the
segment to monetize gas equity.
● Strengthened phasing and design-to-cost approach in projects
execution enabling the Company to reduce financial exposure
and execution risks.
● Optimizing efficiency by means of several initiatives to reduce
operating costs and “Non-Productive Time”.
● Use of Digital Transformation to support asset integrity and
operational efficiency.
Mid-downstream
LNG
PRODUZIONE
CONTRACTED
IDROCARBURI
VOLUMES
CAGR
14 MTPA
+3,6 % 2018-2022
@ 2022
produzione organica
BREAKEVEN
SERM
RISORSE
ESPLORATIVE
COPERTURA
ORGANICA
GREEN
DEGLI
PRODUCTIONS
INVESTIMENTI
€
MID-DOWN-
STREAM
ADJUSTED
OPERATING
PROFIT
FREE CASH
FLOW
CUMULATO
MID-DOWN-
STREAM
ORGANIC
FREE CASH
FLOW
BREAKEVEN
COMPLESSIVO
NUOVI
PROGETTI
IN ESECUZIONE
~1.5 $/bbl
2.5 mld boe
in the long term
nel quadriennio
1 mln ton/year
<40 $/boe
from 2021
nel quadriennio
€1.8 bln
~€22 mld
@ 2022
€4.7 bln
in the four-year plan
25 $/boe
nel quadriennio
GAS & POWER
Growth in economic and financial results in the four-year plan:
adjusted operating profit expected at €0.7 billion in 2022; cumulated
organic free cash flow at €2.3 billion in the 2019-2022 period.
● Growth in LNG business benefitting from the development of
the Asian market, the entry in the new markets and the greater
integration with upstream business for the enhancement and
monetization of gas equity; LNG contracted volumes to 14 MTPA
in 2022 and 16 MTPA in 2025.
● Ongoing restructuring of Eni supply portfolio and reduction of
logistic costs, through contracts renegotiations.
● Increasing integration with other Eni’s businesses, in particular
in LNG and Trading.
● Growth and enhancement of the retail business’ customer base
also by developing new products/services and implementing
transformation initiatives leveraging on accelerating channels
and digitalization. In 2022 customers will increase to around 12
million, up by 22% vs. 2019.
● Geographical rebalancing in Italy in the retail business
leveraging on acquisitions, catching the opportunities arising
from the market consolidation process.
REFINING & MARKETING
Sustainable financial results in the four-year plan with a
cumulated organic free cash flow at €2.6 billion in the 2019-
2022 period.
● Geographical rebalancing of the refining activities, leveraging
on opportunities from Countries characterized by competitive
profitability, in particular the Middle East with the acquisition of
ADNOC Refining share (Abu Dhabi, up by 35% vs. 2018 capacity).
● Breakeven refining margin at 2.7 $/barrel by 2020, following
Ruwais acquisition, maximization of asset integrity and
logistic optimizations. In the long-term breakeven refining
margin at 1.5 $/barrel.
● Ongoing development of green projects (start-up of the
Gela biorefinery and increase of the Venice biorefinery
performance), final market diversification and development of
projects of waste conversion based on circular economy.
● In marketing business, consolidation of market position in
Italy combined with a selective growth abroad, development
of sustainable mobility (increase of alternative fuels offer and
enhanchment in “enjoy” activity).
● Increasing integration with other businesses.
SCENARIO AND STRATEGY$$$$$$$€€ 19
CHEMICALS
Adjusted operating profit to €0.3 billion in 2022; cumulated cash
flow from operations expected at €1.1 billion in the four-year plan.
● Consolidation of resilience to scenario fluctuations, by increasing
balance of the ethylene-polyhethylene supply chain and higher
integration among productive sites.
● Focus of portfolio on differentiated products with higher value
added, through the enhancement of production processes.
● Development of circular economy projects and bio-tech to react to
legislative challenges and market requests on sustainability issues.
● Reduction of GHG emissions in the production processes, increasing
energy efficiency and flexibility of cracker feedstock.
● Development of international presence in the low-cost feedstock areas,
to increase resilience of the industrial system and in areas with higher
growing rates, leveraging on technological driver.
Dividend policy
Eni is committed to a progressive remuneration policy linked to
our underlying earnings and free cash flow growth. In light of the
achieved performance and the expected growth in all businesses,
Eni intends to increase the 2019 cash dividend by 3.6% to €0.86
per share. In addition, in 2019 we start a buyback programme
with an initial capital allocation of €400 million.
In the following years, assuming a leverage steadily below 20%,
the annual capital allocation will amount either to €400 million
in a $60-65 Brent scenario or €800 million with a Brent scenario
above $65/barrel.
Focus on decarbonization
EMISSIONI
DIRETTE
GHG
UPSTREAM
Eni defined a clear strategy to decarbonization integrated in
the business model based on short, medium and long-term
actions. Research and development will play a key role in our
decarbonization strategy and in finding the innovative solutions
vs. 2014
to promote energy transition.
-43 %
GAS FLERED
ZERO
ROUTINE
vs. 2014
-80 %
GNL
CONTRAT-
TUALIZZATO
In the short term, Eni’s strategy is based on the following levers:
● increase of efficiency and reduction of direct GHG emissions:
by 2025 we target to reduce the upstream emission intensity of
Eni’s operated assets by 43% compared to 2014 through projects
aiming at zero gas flaring, reduction of methane fugitive emissions
and the realization of projects based on energy efficiency;
CAPACITÀ
INSTALLATA
DA ENERGIE
RINNOVABILI
16 mton/a
5 GW
● “low carbon” and resilient Oil & Gas portfolio: Eni’s portfolio is
characterized by a high share of natural gas (more than 50%),
a bridge towards reduced future emissions. The main upstream
projects in execution present an average breakeven at a Brent
price of approximately 25 $/barrel, resilient to low carbon
scenario;
● development of renewable sources and green business:
2025 targets
EMISSIONI
FUGGITIVE
the promotion of renewable sources targets an installed power
capacity of approximately 5 GW by 2025.
PRODUZIONE
+3,5 %
vs. 2022
Relating to green business, the second phase of Venice biorefinery
will be completed by 2021 with an increase of capacity to 560
kton/year (compared to the current value of 360 kton/year) and
the start-up, by 2019, of the Gela plant, with a capacity of 720
kton/year. The consolidation of green chemicals is confirmed by
the acquisition in 2018 of the Mossi & Ghisolfi Group bio-activities
and by the development of recycling and recovering projects.
In the medium term, Eni targets the net zero carbon footprint by
2030, relating to direct emissions of the upstream equity assets,
by maximizing the decarbonization initiatives and developing
forestry projects offsetting residual upstream emissions. A central
role will be played by those solutions addressed to capture, store
and reuse CO2. Another lever of our decarbonization path is the
devolopment of circular economy initiatives aimed at waste and
bio-mass valorization in order to extract new energy, new products
or materials and revitalized dismissed or decommissioned assets.
DIRECT GHG
UPSTREAM
EMISSIONS
INTENSITY
-43 %
vs. 2014
GAS
FLARED
0 routine
UPSTREAM
METHANE
FUGITIVE
EMISSIONS
-80 %
vs. 2014
HYDROCARBON
PRODUCTION
CAGR
+3.5 %
vs. 2022
LNG
CONTRACTED
VOLUMES
INSTALLED
CAPACITY
FROM
RENEWABLES
16 MTPA
5 GW
SCENARIO AND STRATEGYEni Annual Report 2018
20
INTEGRATED
RISK MANAGEMENT
The integrated risk management (IRM) process is aimed at ensuring that management
takes risk-informed decisions, with adequate consideration of actual and prospective
risks1, including medium and long-term ones, within the framework of an organic
and comprehensive vision. IRM Model also aims to strengthen the organization
awareness, at any level, that suitable management and evaluation risk may impact
the delivery of corporate targets and value.
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 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.
For this purpose, Eni’s CEO, 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
CONTROL AND RISK COMMITTEE/BOARD OF AUDITORS
CHAIRMAN
CEO
RISK COMMITTEE
COMPLIANCE COMMITTEE
Integrated Risk Management
Integrated Compliance
1st line
“Line” managers - risk owners
2nd line
Risk & Control functions*
3rd line
Internal Audit
(*) Including Integrated Risk Management function.
(1) Potential events that can affect Eni’s activities and whose occurance could hamper the achievement of the main corporate objectives.
21
Integrated Risk Management Process
The IRM Model is implemented through a process of integrated
management which is both continuous and dynamic and leverages
on the risk management systems already adopted by each business
unit and corporate processes, promoting harmonization with
methodologies and specific tools of the IRM Model. The process,
regulated by the “Management System Guideline (MSG) Integrated
Risk Management” published on July 2016, has been revised and
broadened to strengthen the integration with the decision-making
process. The IRM process includes six sub-processes: (i) risk
management guidelines, (ii) risk strategy, (iii) risk assessment
& treatment, (iv) risk monitoring, (v) risk reporting, and (vi) risk
culture. It takes a top-down and risk-based approach, starting from
the definition of Eni’s Strategic Plan (risk strategy), by identifying
specific de-risking targets, the analysis of the underlying risk profile
of the Plan, also through stress test for economic-financial resiliency
vs. strategic targets, as well as the identification of strategic
treatment actions. These activities, performed coherently and
integrated with the strategic planning process, support the Board’s
assessments regarding the acceptability of the risk profile of the
Strategic Plan subject to his approval. The process continues with
the periodic cycles of risk assessment & treatment and monitoring,
the profile analysis on specific risks of the relevant transactions,
as well as the integrated analysis on the risks in common with
certain business and/or functions. The risk evaluation is carried out
through metrics considering both potential quantitative (financial-
economic or operations) and qualitative (like environment, health
and safety, social, reputation, etc.) aspects. The prioritization is
based on a multidimensional arrays that allows to obtain the risk
level as combination of probability cluster and impact cluster. All
risks are evaluated and expressed following an inherent and a
residual level (taking into account the implemented actions of
mitigation). Eni’s top risks portfolio consists of 18 risks classified
in: (i) external risks, (ii) strategic risks and, finally, (iii) operational
risks (see Objectives, risks and treatment actions on the following
pages). In 2018, two assessment sessions were performed: the
Annual Risk Profile Assessment performed in the first half of the
year, involving 80 subsidiaries in 27 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. The two assessment results were submitted
to Eni’s management and control bodies in July and December
2018. In addition, three monitoring processes were performed on
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 2018.
INTEGRATED RISK MANAGEMENT PROCESS
1
RISK MANAGEMENT GUIDELINES
IRM
INTEGRATED RISK MANAGEMENT
Top-down and risk-based approach
2
3
4
5
RISK STRATEGY
RISK ASSESSMENT & TREATMENT
RISK MONITORING
RISK REPORTING
6
RISK CULTURE
The risk culture develops a common language and spread an appropriate risk management culture across all organizational
levels to build awareness that suitably identifying, assessing and managing various types of risk can affect the achievement
of objectives and the value of the company. Risk culture, moreover, promotes a greater inclusion of risk management in the
company’s processes to ensure consistency in methodology, and in general, in management tools and in risk control.
INTEGRATED RISK MANAGEMENTEni Annual Report 2018
22
Targets, risks and treatment measures
K
S
I
R
L
A
N
R
E
T
X
E
K
S
I
R
I
C
G
E
T
A
R
T
S
K
S
I
R
I
L
A
N
O
T
A
R
E
P
O
COUNTRY
MAIN RISK
EVENTS
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.
TREATMENT
MEASURES
• Geographic 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 social
development and sustainability projects in order to enhance local content and welfare promotion within local communities
(production for domestic market, access to energy, economic diversification, local development, health and education);
Implementation of the security management system supported by specific site’s analysis of the preventive measures.
•
→ Ref. pages 94-96
CLIMATE CHANGE
MAIN RISK
EVENTS
Climate change referred to the possibility of change in scenario/climatic conditions which may generate phisical risks and
connected to energy transition (legislative, market, technological and reputational risks) on Eni’s businesses in the short,
medium and long term.
TREATMENT
MEASURES
• Decarbonization strategy integrated in Eni’s business model based on: carbon footprint reduction, resilient Oil & Gas
portfolio, development of renewables and green energy businesses, commitment in R&D and climate partnership;
• Structured governance on climate with a central role of the Board in managing main issues connected with climate
change; presence of specific committees to support the Board; establishment of the Advisory Board and Eni’s programs
focused on climate change issues;
Inclusion of targets related to “climate strategy” in incentive plan for managers, consistent with guidelines of Eni’s
Strategic Plan;
•
• Leadership on climate-related financial disclosures and other initiatives: joining in the Task Force on Climate-related
Financial Disclosures (TCFD) of Financial Stability Board and in “TCFD European Oil & Gas Preparers’ Forum” for drawing
up industry guidelines to support the implementation of the Recommendations issued by TCFD and participation in
different initiatives at international level.
→ Ref. pages 99-100
ACCIDENTS
MAIN RISK
EVENTS
Blow-out risks and other relevant accidents affecting the upstream assets, refineries and petrochemical plants, as well as
the transportation of hydrocarbons by sea and land (i.e. fires, explosions, etc.) with impact on people and assets damages,
company profitability and reputation.
TREATMENT
MEASURES
• Upgrading methodology to classify complex wells (Well Complexity & Economic Index) and geologic “Real time
monitoring” of well drilling phases;
• Asset Integrity Management, Maintenance Management;
• BART (Baseline Assessment Risk Tool) implementation, Simultaneous Operations Operating Plans;
• Process Safety Reinforcement Plan, Emergency Preparedness and Response Plans;
•
Identification of Safety Critical Equipment and use of the “risk based inspection” methodology (API 581 standard)
and Fitness for Service (API 579 standard) for the definition of the optimum inspection programmes and the
identification of the intervention priorities of preventive maintenance on the basis of identified defects and
of the plant components executability;
• Development of innovative digital tools and big data analystics to improve operational performance and asset integrity.
Particularly, the implementation of the Digital Lighthouse project from Val d’Agri to other upstream and downstream top
value assets (e.g. centralized room for real time monitoring of productive assets, smart operators, integrated operating
centres, strategic equipment modelling and integrated competence centre);
Involvement of First Parties to strengthen the culture of security in joint-control JV;
• Specific technological development and emergency management plans; specific HSE audit and plants monitoring;
•
• Management and continuous monitoring of shipping operation through third operators, vetting activities.
→ Ref. pages 89-94
INTEGRATED RISK MANAGEMENT
23
Eni’s target ˛
Company profitability
Corporate Reputation
Relationship with Stakeholders, Local development
COUNTRY/COUNTERPARTY
EVOLUTION IN G&P LEGISLATION
Upstream Credit and Financing risk related to the credit proceeds delay
or cost recovery from National Oil Companies (credit) or joint venture
partners (financing).
Potential deteriorating legislative/regulatory, national and international
environment, in the Gas & Power segment with potential impacts to
corporate profitability.
UPSTREAM
• Finalization of specific agreements on repayment plans of third parties
• Control of legislative and regulatory framework evolution in order to
simplify/mitigate impacts on business;
receivables;
• Securitization package with in-kind withdrawals and/or utilization
of dedicated escrow account;
• Mitigation collaterals (sovereign guarantees, parent company
guarantees, credit letters);
• Carry agreement negotiations and offsetting with the NOC’s through
debt positions in the Country.
→ Ref. page 101
• Recovery/optimization actions on logistical costs through asset backed
trading activities and contractual revision on capacity.
→ Ref. pages 97-98
STAKEHOLDER
LONG-TERM GAS CONTRACTS
Relationships with local and international stakeholders on Oil & Gas
industry activities, with impacts also in the media.
Potential differences between the cost of supply and the minimum
off take obligations in take-or-pay long-term gas supply contracts
compared to current market conditions and management of arbitrations/
negotiations with gas suppliers.
•
Integration of targets and sustainability projects (i.e. Community
Investment) within the Strategic Plan and incentive program;
• Prolonged supply portfolio restructuring process through the
renegotiation of price-volume conditions;
• Focused communication plan and communication initiatives aimed at
• Portfolio balancing by the sale to hubs of volumes not intended to
spreading Eni’s strategy and activities, also through social media with a
mainly institutional target;
• Meeting and dialogue with stakeholders initiatives and strenghtening
of presence in the critical areas in order to intensify the relationship
management with local authorities and territories;
• Development of measurement instruments and monitoring of corporate
reputation (RepLab) for all stakeholders categories.
→ Ref. pages 94-96
commercial segments, both in Italy and in Northern Europe;
• Continuous control of arbitration management and negotiations by
dedicated units.
→ Ref. pages 96-97
INVESTIGATIONS AND PROCEEDINGS
CYBER SECURITY
Environmental and health proceedings as well as evolution
in HSE legislation may trigger contingent liabilities, impact on
company profitability (costs for remediation activities and/or plant
implementation), operating activities and corporate reputation.
Involvement in anti-corruption investigations and proceedings.
Cyber Security and industrial Espionage.
• 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;
• Focused communication initiatives;
• Specialized assistance supporting Eni SpA and Italian and foreign
subsidiaries;
• Centralized governance model of Cyber Security, with units dedicated to
cyber intelligence and prevention, monitoring and management of cyber
attacks;
• Rules dedicated to IT security management and information protection;
• Operating plans aimed at increasing security of industrial sites (in
Italy and abroad), training and awareness initiatives dedicated to Eni’s
employees;
• Evolution of methodology aimed at evaluation of Cyber Security risk for
a more efficient and effective management of cyber risk, in particular
through a model review of economic and operational estimated impact
and risk exposure for each asset.
• Audit activities on compliance with anti-corruption regulations and 231
→ Ref. pages 101-102
Legislative Decree.
→ Ref. page 100
INTEGRATED RISK MANAGEMENTEni Annual Report 2018 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,
recognising the need for a deeper dialogue with the market and in
continuity with initiatives undertaken since 2013, on January 30,
2018, Eni organised a “corporate governance roadshow” in London
involving the Chairman of the Eni Board of Directors and the main
institutional investors of Eni to present among other things the
main initiatives Eni has undertaken, with a focus on the internal
control and risk management system, the Advisory Board and the
Company’s commitment (from the Board on down) to an even
stronger compliance culture and to climate change actions.
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.
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
Slate
3
Independence(a)
Gender diversity
Age(b)
2
2
3
2
6
7
6
5
majority
minority
independent
non independent
male
female
40–50 years
51–60 years
61–70 years
(a) Independence as defined by applicable law.
(b) Figures at December 31, 2018.
(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 itself and, on its
behalf, to the Chairman, must also meet appropriate independence
and other requirements5.
The following chart summarises the Company’s corporate governance
structure at March 14, 2019:
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
EY 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. Until December 31, 2018 Marco Bollini.
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 2018
26
The following is a chart setting out the current macro-organizational structure of Eni SpA at March 14, 2019:
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(c)
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(d)
L. Lusuriello
Chief Digital
Officer(e)
M. Mondazzi
Chief Financial
Officer
C. Granata
Chief Services
& Stakeholder
Relations Officer
L. Bertelli
Chief
Exploration
Officer
A. Puliti
Chief Development,
Operations
& Technology
Officer
L. Cosentino
Energy Solutions
Executive Vice
President
A. Vella
Chief Upstream
Officer
M. Mantovani
Chief Gas & LNG
Marketing
and Power
Officer
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) In office since January 1st, 2019.
(d) From January 1st, 2019. Until 31 December 2018, Senior Executive Vice President Legal Affairs.
(e) Since September 18, 2018.
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
(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
in the Company, such as the officer in charge of preparing financial
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.
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 four times in the last
seven years, most recently in February 2018 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 2018. 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 2018, in continuity with previous
initiatives, additional training sessions were held with visits to labs in
the upstream and renewables operational areas, as well as to the Zohr
plant in Egypt 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.
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.
(7) For more information on the Board Review process, see the section devoted to that process in the Corporate Governance and Shareholding Structure Report 2018.
(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 2018 28
THE MAIN SUSTAINABILITY ISSUES ADDRESSED BY THE BOARD IN 2018
• 2017 financial statements9, including the Consolidated Non-Financial Statement;
• the Remuneration Report, including sustainability targets in the definition of performance plans;
• 2017 HSE Performance;
• Voluntary Eni Report on Sustainability (so called “Eni for”);
• Sustainability scenario;
• Update of the Statement in compliance with the UK Modern Slavery Act;
• Eni’s Statement on respect for human rights;
• Climate Governance.
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 2018, the Advisory Board met three times,
in April, June and September, to address matters related to
geopolitical developments, Eni’s strategic positioning in a
decarbonization scenario, energy market developments, the
energy industry transformation and renewable energy.
Remuneration Policy
Eni’s Remuneration Policy for its Directors and top management 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.
With regard to sustainability issues, the CEO objectives set for the
year 2019 are focused on environmental matters as well as on
human capital aspects.
The objectives of the Chief Officers of Eni business segments
and other Managers with strategic responsibilities are assigned
on the basis of those assigned to top management focused on
stakeholders’ perspectives, as well as on individual objectives
assigned in relation to the responsibilities inherent the single
managerial position, under the provisions of Company’s Strategic
Plan. 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, on an annual basis, for an
advisory vote at the Shareholders’ Meeting.
(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 2018, please see the relevant section in the Corporate Governance and Shareholding Structure Report 2018.
(11) For more information, please see the Eni website, in the Governance section.
GOVERNANCE 29
2018 TARGETS FOR THE 2019 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 system12
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 (as an essential part of the Company’s Model 231), 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.
(12) For more information, please see the Corporate Governance and Shareholding Structure Report 2018.
07_Governance_ING.indd 29
10/05/19 09:21
GOVERNANCEEni Annual Report 2018
30
EXPLORATION
& PRODUCTION
PERFORMANCE
VS. BRENT
EXCELLENCE
IN OPERATIONS
MOVEMENTS IN NET PROVED RESERVES
(bboe)
Adjusted operating performance (€ million)
Brent ($/boe)
43.69
+24%
54.27
+31%
+110%
+107%
3
7
1
,
5
7
1
0
2
4
9
4
2
,
6
1
0
2
71.04
0
5
8
0
1
,
8
1
0
2
Oil and gas production (mmboe/d)
GHG emissions/100% operated
hydrocarbon gross production
(tonnes CO₂eq/kboe)
Proved reserves
Net organic additions 2015–2018
Production 2015–2018
Portfolio 2015–2018
23.56
9
5
7
.
1
6
1
0
2
22.75
21.44
6
1
8
.
1
7
1
0
2
1
5
8
.
1
8
1
0
2
0
6
2
.
8
9
.
1
6
3
0
.
Organic reserve
replacement
ratio
2015–2018
131%
9
8
6
.
5
1
0
2
5
1
.
7
8
1
0
2
Performance of the year
● Total recordable injury rate (TRIR) was 0.30, a level that is in
the lowest range of the industry average; confirming Eni’s
commitment to awareness and dissemination of the safety
culture, achieving a reduction of 46% compared to 2014.
● Emissions from flaring were down by 8% from 2017 due to the
achievement of the zero flaring configuration in the Burun
field in Turkmenistan and the reduction of emergency flaring.
This result confirms that we are well on track on our long-
term target of zero routine flaring in 2025. In 2018, capital
expenditure of flaring down projects was €39 million, in
particular in Nigeria and Libya.
● Upstream GHG intensity index was positive with a reduction of
6% from 2017 and 20% from 2014. We achieved these results
leveraging on the reduction of emissions from flaring, the gas
production of the Zohr field in Egypt and the Jangkrik field in
Indonesia as well as an increase production of Goliat field in
Norway, which is an asset with lower intensity emission than the
upstream average. This performance is in line with the target of
43% reduction in 2025 compared to 2014.
● Water reinjection was 60% in 2018, leveraging on the ongoing
programs in certain operational plants, in particular in Egypt and
Ecuador.
● In 2018, the E&P segment recorded the best result of the last
four years, with an adjusted operating profit more than doubled
compared to 2017. This performance reflected more than
proportionally strong trend registered in hydrocarbons price
scenario in the first ten months of 2018 (a rise of 31% in price
of the Brent market benchmark in dollar term) and production
growth, which was boosted by a larger weight of barrels with a
higher profit per boe.
● Oil and natural gas production was a record level of 1.851
million boe/d, up by 2.5% from 2017 net of price effects.
Start-ups and ramp-ups added more than 300 kboe/d to the
production level of 2018.
● Net proved reserves at December 31, 2018 amounted to 7.15
bboe based on a reference Brent price of $71.4 per barrel.
The all sources replacement ratio was 124%, 100% of organic
replacement ratio (105% net of price effects); 131% three-year
average organic replacement ratio. The reserves life index was
10.6 years (10.5 years in 2017).
DISCOVERED
RESOURCES
600 mmboe
at a unit cost
of 1.5 $/boe
EXPANDING
FOOTPRINT IN THE
MIDDLE EAST
~400 kboe/d
production target
in the long term
RECORD
PRODUCTION
1.85 mmboe/d
+2.5% from 2017
CASH FLOW
PER BOE
22.5 $/boe
achieved earlier
than planned
€$ 31
Portfolio management
● Signed strategic agreements with the United Arab Emirates,
Oman and Bahrain. In particular, the agreements reached in the
United Arab Emirates and Oman include exploration, development
and production of oil and gas fields, offshore and onshore. The
agreement with Bahrain will create further exploration offshore
opportunities. Technological innovation, scientific expertise,
accelerated start-up and collaboration with host Countries
allowed Eni to expand its footprint in a strategic area of the
energy industry development:
- signed two Concession Agreements related to the acquisition
of a 5% participating interest in the Lower Zakum oil field and
a 10% participating interest in the Umm Shaif and Nasr oil,
condensates and natural gas fields, in the offshore of Abu
Dhabi, with duration of 40 years;
- awarded a 25% interest of the Ghasha offshore concession in
the Abu Dhabi. The concession includes Hal, Ghasha, Dalma
gas fields and certain offshore fields in the Al Dhafra area.
Production start-up is expected in 2022. In January 2019, Eni
was awarded the operatorship of the Block 1 and 2 with a 70%
interest, located offshore of the Country;
- awarded the offshore exploration Block 47 in Oman and signed
a Head of Agreement for the exploration Block 77, located
onshore of the Country. Eni will operate both blocks with a 90%
interest and 50% interest, respectively;
- signed a Memorandum of Understanding with the National
Oil and Gas Authority of the Kingdom of Bahrain (NOGA). The
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 2018 additions to the Company’s reserve
backlog were 620 million boe of new equity resources.
Main discoveries or appraisal activities were in Egypt,
Cyprus, Norway, Angola, Nigeria, Mexico and Indonesia.
The overall commercial success rate was 66% net to Eni, best
performance of the last eighteen years.
● Finalized an agreement with BP and National Oil Company
in Libya to boost exploration activities in the Country. The
agreement strengthened the parties’ commitment to social
development in the Country through the implementation of
specific education and technical training programs.
● Awarded a 40% interest of the Blocks 4 and 9 located in the
offshore Lebanon.
● Awarded a 100% interest of 124 exploration licenses located in
the Eastern North Slope in Alaska with high mineral potential and
nearby to existing production facilities.
● Signed the contract for the exploration and development rights
of the offshore block A5-A, in the deep offshore of Zambesi.
agreement includes an exploration program for the offshore
Block 1, an area still largely unexplored, located in the offshore
northern territorial area of the Country;
- awarded three onshore exploration concessions in the Emirate
of Sharjah.
● Dual Exploration Model:
- disposal of 10% interest of the Shorouk concession in Egypt,
where is located the supergiant gas Zohr field, to Mubadala
Petroleum, an United Arab Emirates oil company;
- farm-out of part of Eni’s interest in the Nour exploration license
in Egypt to BP and Mubadala companies. These companies
purchased a 25% interest and 20% interest, respectively;
- finalized swap agreements of stake in explorations assets
located in Mexico with Lukoil company;
- signed an agreement to divest a 35% interest in the Area 1
license, where 2.1 billion of boe in place discovered, to Qatar
Petroleum oil company.
● Strengthened the upstream activity in Norway with the the
business combination between Eni Norge and Point Resources,
leading to the creation of Vår Energi, an equity-accounted joint
venture (Eni’s interest 69.6%) that will develop the activities of
the two partners in Norway targeting a production plateau of 250
kboe/d in 2023.
Eni was awarded the operatorship of the block with a 59.5%
interest.
● Awarded a 65% interest in the Area 24 license and a 75% interst in
the Area 28 license located in offshore Mexico. Eni operates both
licenses.
● Replacing portfolio of exploration leases in the year, added
approximately 29,300 square kilometers of new acreage.
● Exploration and appraisal activity was €750 million (€715 million
in 2017) and included exploration expenditure and prospecting,
geological and geophysical expenses in the year. Exploration and
appraisal activity covered approximately 45% of total activity in
2018 and were conducted in particular in Indonesia, Norway,
United States, Angola and Vietnam.
● In 2018 exploration expenses were €380 million (€525 million in
2017) and included the write-off of unsuccessful wells amounting
to €93 million (€252 million in 2017), 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 unsuccesful drilling activities mainly concerned projects in
Vietnam and Morocco. In addition, 80 exploratory drilled wells are
in progress at year-end (40.3 net to Eni).
Eni Annual Report 2018OPERATING REVIEW | EXPLORATION & PRODUCTION 32
Development activity
● During the year production ramp-up was achieved earlier than
scheduled at the giant project with a higher profit per boe such
as the Zohr and Noroos fields in Egypt, the Jangkrik field in
Indonesia, the OCTP project in Ghana as well as the Nenè Marine
Phase 2 project in Congo. In addition as planned production
started up at the Ochigufu, Vandumbu and UM8 fields in the
operated Block 15/06 in Angola, the OCTP gas project to support
domestic market in Ghana and the Bahr Essalam Phase 2 and
the Wafa compression projects in Libya.
● The co-venturers of Area 4 secured long-term agreements for the
purchase of LNG volumes, an important step towards making the
final investment decision of the first phase of the Rovuma LNG
Project, for the construction of two LNG trains with a capacity of
7.6 mmtonnes/y each and obtaining the project financing.
● Sanctioned the Cabaça North & Cabaça South-East UM4/5
development programs within the East Hub project in the Block
15/06 in Angola. Start-up is expected in 2021. Furthermore, Eni
signed an amendment of the Block 15/06 PSA contract that
defines an additional exploration acreage in the western area of
the block. The agreement confirms Eni’s strategy of the fast-track
discoveries developments leveraging on the synergies with
existing facilities.
● Sanctioned the operated projects of Area 1 in Mexico with
the pilot project’s planned start-up in 2019 and the Merakes
discovery in Indonesia, leveraging on the synergy with the
existing infrastructures of the Jangkrik field. Overall, in 2018,
six projects were sanctioned (in addition to those previously
mentioned, in Italy, Egypt and Congo).
● Signed an agreement to purchase of 70% interest and the
extension strengthen Eni’s gas portfolio and confirm the success
of Eni’s strategy of near field exploration which revamped
production in the Nile Delta area. In addition, Egyptian Authorities
approved five-years extension of the Ras Qattara concession.
Following this agreement, a new exploration campaign will
start-up to discover additional hydrocarbons reservers and will
allow further exploration activities in the Western Desert Area.
● In March 2019, Eni signed an agreement to divest a 30% interest
in the Tarfaya Offshore Shallow exploration license in Morocco
to Qatar Petroleum, retaining the operatorship of the permit with
a 45% interest. The agreement is subject to approval by
the relevant Authorities.
● Signed a memorandum of understanding with the United Nations
Development Programme (UNDP) to support sustainable
development and help achieve the Sustainable Development
Goals (SDGs), in particular access to energy by 2030, climate
change initiatives and the protection, restoration and sustainable
use of the ecosystem. The agreement confirmed Eni’s
commitment to support access to energy, particularly in Africa,
and as integrated in our business model.
● Signed with the Food and Agriculture Organization (FAO) a
collaboration agreement to promote access to safe and clean
water in Nigeria, in particular in the northeast areas, by drilling
boreholes, both for domestic use and irrigation purposes.
In particular, FAO will support to identify the operations areas
as well as technical and know-how collaboration while Eni
drilling boreholes which will be powered by photovoltaic
systems and will provides for training program of use and
maintenance to sustainability in the long term.
operatorship of the Oooguruk field, where Eni already holds 30%
interest. The Oooguruk field is already productive from 2008,
in the Beaufort Sea of the North Slope in Alaska. Production
facilities provide for safe and environmentally responsible
operations. Additionally, Eni will leverage on the existing excellent
relationships and cooperation with the local communities. This
agreement will add immediately production and implement
significant operational synergies and optimizations with the
operated Nikaitchuq field.
● Net capex amounted to approximately €6 billion (€6 billion in
2017) and excluded the capex pertaining to a 10% divested
interest in the Zohr project (€170 million) incurred from
January 1, 2018 to the closing of the transaction (end of June
2018), which were reimbursed to Eni by the buyer and, as
part of the financing agreements with the Egyptian partners
relating to the Zohr project, the Company cashed in €280
million as an advance on future gas supplies to Egyptian
state-owned companies.
● Approved ten-years extension of the Great Nooros Area’s assets,
the most rich basin in the Nile Delta in offshore Egypt. This lease
● In 2018, overall R&D expenditure of the Exploration & Production
segment amounted to €96 million (€83 million in 2017).
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 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
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.
In order to calculate the net present value of Eni’s equity
reserves, actual prices applicable to hydrocarbon sales, price
(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 SGS Company also provided an independent certification.
(3) The reports of independent engineers are available on Eni website eni.com section Publications/Annual Report 2018.
Eni Annual Report 2018OPERATING REVIEW | EXPLORATION & PRODUCTION 34
adjustments required by applicable contractual arrangements
and other pertinent information are provided by Eni to third
party evaluators. In 2018 Ryder Scott Company, DeGolyer and
MacNaughton and Societé Generale de Surveillance (SGS)
provide an independent evaluation of approximately 26% of Eni’s
total proved reserves at December 31, 20184, confirming, as in
previous years, the reasonableness of Eni internal evaluation5.
In the 2016-2018 three-year period, 95% of Eni total proved reserves
were subject to independent evaluation. As at December 31, 2018,
the M’Boundi field in Congo was the main Eni property, which did not
undergo an independent evaluation in the last three years.
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 2018 proved reserves were as follows:
Estimated net proved reserves at December 31, 2017
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, 2018
Reserves replacement ratio, all sources
Reserves replacement ratio, organic
Organic reserves replacement ratio, net of price effect
(mmboe)
Consolidated
subsidiaries
6,430
Equity-accounted
entities
560
813
(41)
(102)
3
711
(38)
772
(196)
(650)
6,356
(99)
362
(26)
797
%
Total
6,990
673
166
(676)
7,153
124
100
105
Net proved reserves as of December 31, 2018 were 7,153 mmboe,
of which 6,356 mmboe of consolidated subsidiaries. Net additions
to proved reserves were 673 mmboe and derived from: (i)
extensions and discoveries were up by 169 mmboe mainly due
to the final investment decisions made for the operated projects
of Area 1 in offshore Mexico, Merakes in Indonesia and Argo and
Cassiopea offshore Italy; (ii) revisions of previous estimates were
up by 491 mmboe and derived from progress in development
activities at the Zohr and Nidoco NW projects in Egypt and at the
Kashagan project in Kazakhstan; and (iii) improved recovery were
up by 13 mmboe mainly reported in particular in Egypt and Iraq.
These increases were partly offset the de-booking of 106 mmboe
of proved undeveloped reserves at a certain project driven by a
deteriorating local operational environment.
Net additions were impacted by unfavorable price effects, leading
to a downward revision of 38 mmboe, due to an increased Brent
price used in the reserves estimation process up to 71.4 $/bbl in
2018 compared to 54.4 $/bbl in 2017.
Portfolio transactions of 166 mmboe comprised: (i) the purchase of
interests in the Concessions Agreements of Lower Zakum and Umm
Shaif and Nasr in Abu Dhabi; (ii) the business combination between Eni
Norge AS and Point Resources AS; and (iii) the disposal of a 10% interest
in the Zohr project to Mubadala Petroleum and other minor assets.
The organic reserves replacement ratio6 was 100% and all sources
additions was 124%. These ratios include the de-booking of proved
undeveloped reserves at a certain project (down 15 percentage
points of reserves replacement ratio).
The reserves life index was 10.6 years (10.5 years in 2017).
PROVED UNDEVELOPED RESERVES
Proved undeveloped reserves as of December 31, 2018 totalled 2,309
mmboe, of which 1,127 mmbbl of liquids mainly concentrated in Africa
and Asia and 6,458 bcf of natural gas mainly located in Africa. Proved
undeveloped reserves of consolidated subsidiaries amounted to 975
mmbbl of liquids and 6,121 bcf of natural gas. Movements in Eni’s 2018
proved undeveloped reserves were as follows:
(mmboe)
Proved undeveloped reserves as of December 31, 2017
Reclassification to proved developed reserves
Extensions and discoveries
Revisions of previous estimates
Improved recovery
Purchases of minerals in place
Sales of minerals in place
Proved undeveloped reserves as of December 31, 2018
2,629
(777)
166
278
6
280
(273)
2,309
(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 2018.
(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 2018, total proved undeveloped reserves decreased by 320
mmboe mainly due to: (i) progress in maturing PUDs to proved
developed (down by 777 mmboe); (ii) extensions and discoveries
(up by 166 mmBOE) due to the final investment decision made
for the Area 1 project offshore Mexico and the Merakes project in
Indonesia; (iii) revisions of previous estimates (up by 278 mmboe)
mainly reported in Egypt due to the development activity of the
Zohr project and included the de-booking of 106 mmboe of proved
undeveloped reserves at a certain project driven by a deteriorating
local operational environment; (iv) improved recovery (up by 6
mmboe) in particular in Iraq; (v) sales of minerals-in-place (down
by 273 mmboe) related to disposals in Egypt and other minor
assets as described above; and (vi) purchase of minerals-in-place
(up by 280 mmboe) related to Abu Dhabi transaction and the
business combination in Norway as above mentioned.
During 2018, Eni matured 777 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
related to the following fields/projects: Zohr (Egypt), Kashagan
(Kazakhstan), Bahr Essalam and Wafa (Libya) and Sankofa
(Ghana).
In 2018, capital expenditures amounted to approximately €6.2
billion and was made to progress the development of proved
undeveloped reserves.
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 0.6 bboe of proved undeveloped
reserves have remained undeveloped for five years or more at the
balance sheet date and decreased 0.4 bboe from 2017 due to the
progress in development activities made in Kazakhstan, Iraq and
Libya as well as the de-booking of of proved undeveloped reserves
at a certain project driven by a deteriorating local operational
environment. The proved undeveloped reserves that have
remained undeveloped for five years or more at the balance sheet
date mainly related to: (i) the Kashagan project in Kazakhstan
(0.1 bboe) due to the completion of ongoing development activity
(for further information see Main exploration and development
projects - Kashagan); (ii) 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; and (iii) certain
Libyan gas fields (0.4 bboe) where development completion
and production start-ups are planned according to the delivery
obligations set forth in a long-term gas supply agreements
currently in force. In order to secure fulfillment of the contractual
delivery quantities, Eni will implement phased production start-up
from the relevant fields which are expected to be put in production
over the next several years.
Eni Annual Report 2018OPERATING REVIEW | EXPLORATION & PRODUCTION 36
Estimated net proved hydrocarbons reserves
)
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
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
)
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
(
176
132
44
264
228
36
454
287
167
281
205
76
809
507
302
767
556
211
307
124
183
163
143
20
9
8
1
3,230
2,190
1,040
13
13
15
8
7
140
22
118
168
43
125
2016
977
845
132
878
801
77
3,738
1,732
2,006
5,520
799
4,721
2,767
1,651
1,116
2,485
2,239
246
1,003
280
723
353
338
15
741
559
182
18,462
9,244
9,218
15
15
368
104
264
4
4
3,484
1,782
1,702
3,871
1,905
1,966
s
n
o
b
r
a
c
o
r
d
y
H
)
e
o
b
m
m
(
354
287
67
426
374
52
1,139
605
534
1,293
352
941
1,317
809
508
1,221
966
255
491
175
316
227
205
22
145
111
34
6,613
3,884
2,729
14
14
82
26
56
2
2
779
349
430
877
391
486
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
Total including equity-accounted entities
Developed
Undeveloped
3,540
2,413
1,127
19,724
13,266
6,458
7,153
4,844
2,309
3,422
2,263
1,159
19,472
11,451
8,021
6,990
4,361
2,629
3,398
2,233
1,165
22,333
11,149
11,184
7,490
4,275
3,215
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 536 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 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 88% of delivery
commitments.
Eni has met all contractual delivery commitments as of December
31, 2018.
OIL AND GAS PRODUCTION
In 2018, oil and natural gas production averaged 1,851 kboe/d, the
highest level ever achieved. This performance was driven by ramp-
ups at fields started up in 2017, mainly in Egypt, Indonesia, Angola,
Congo and Ghana and the 2018 start-ups (with a total contribution
of over 300 kboe/d), higher productions at the Kashagan field, Goliat
field in Norway and Val d’Agri in Italy, as well as the acquisition of
the two Concession Agreements Lower Zakum (5%) and Umm Shaif
and Nasr (10%) producing offshore in the United Arab Emirates.
These positives were partly offset by negative price effects at
PSAs contracts, lower-than-expected produced gas volumes due to
the impact of exogenous factors in certain Countries, the decline
of mature fields as well as certain one-off events (termination
of the Intisar contract in Libya and unplanned shutdowns).
When excluding price effects (down approximately 10 kboe/d),
hydrocarbon production increased by 2.5% in the full year.
Liquids production amounted to 887 kbbl/d. The ramp-ups of the
period and the acquisition in the United Arab Emirates were partly
offset by price effects and mature field declines.
Natural gas production amounted to 5,261 mmcf/d. Production
ramp-ups and start-ups were offset by exogenous factors in
certain Countries
Oil and gas production sold amounted to 625 mmboe. The
50.6 mmboe difference over production (675.6 mmboe in
2018) mainly reflected volumes of hydrocarbons consumed
in operations (43.5 mmboe), changes in inventory levels and
other variations. Approximately 70% of liquids production sold
(320 mmbbl) was destined to Eni’s mid-downstream business.
About 20% of natural gas production sold (1,665 bcf) was
destined to Eni’s Gas & Power segment.
Eni Annual Report 2018OPERATING REVIEW | EXPLORATION & PRODUCTION 38
Annual oil and natural gas production(a)(b)
Consolidated subsidiaries
Italy
Rest of Europe
Croatia
Norway
United Kingdom
North Africa
Algeria
Libya
Tunisia
Egypt
Sub-Saharan Africa
Angola
Congo
Ghana
Nigeria
Kazakhstan
Rest of Asia
China
Indonesia
Iraq
Pakistan
Turkmenistan
United Arab Emirates
Americas
Ecuador
Trinidad & Tobago
United States
Australia and Oceania
Australia
Equity-accounted entities
Angola
Indonesia
Tunisia
Venezuela
)
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
)
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
(
2016
17
40
31
9
60
28
31
1
28
91
40
26
25
24
28
1
1
23
3
25
4
21
1
1
314
1
1
5
7
172
184
10
95
79
584
43
536
5
218
170
18
54
98
93
90
18
7
63
2
94
26
68
42
42
1,647
11
7
2
93
113
s
n
o
b
r
a
c
o
r
d
y
H
)
e
o
b
m
m
(
49
73
2
48
23
167
36
129
2
68
122
43
36
43
41
45
1
4
25
12
3
43
4
5
34
8
8
616
2
2
2
22
28
Total
324
1,920
676
311
1,920
663
321
1,760
644
(a) Includes Eni’s share of equity-accounted equities.
(b) Includes volumes of hydrocarbons consumed in operations (43.5, 35.2 and 32.1 mmboe in 2018, 2017 and 2016, respectively).
OPERATING REVIEW | EXPLORATION & PRODUCTION
39
Daily oil and gas production(a)(b)
Consolidated subsidiaries
Italy
Rest of Europe
Croatia
Norway
United Kingdom
North Africa
Algeria
Libya
Tunisia
Egypt
Sub-Saharan Africa
Angola
Congo
Ghana
Nigeria
Kazakhstan
Rest of Asia
China
Indonesia
Iraq
Pakistan
Turkmenistan
United Arab Emirates
Americas
Ecuador
Trinidad & Tobago
United States
Australia and Oceania
Australia
Equity-accounted entities
Angola
Indonesia
Tunisia
Venezuela
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
s
a
g
l
a
r
u
t
a
N
)
d
/
f
c
m
m
(
2016
471.2
501.8
26.5
258.3
217.0
1,594.8
115.5
1,464.8
14.5
597.4
464.3
49.0
148.5
266.8
254.0
245.8
48.5
19.2
172.1
6.0
256.4
69.7
186.7
113.9
113.9
4,499.6
29.1
18.8
4.9
254.8
307.6
s
d
i
u
q
i
L
)
d
/
l
b
b
k
(
47
109
86
23
165
77
84
4
76
247
108
71
68
65
78
2
3
64
9
69
10
59
3
3
859
1
1
3
14
19
s
n
o
b
r
a
c
o
r
d
y
H
)
d
/
e
o
b
k
(
133
201
5
133
63
458
98
353
7
185
333
118
98
117
111
123
2
12
67
32
10
116
10
13
93
24
24
1,684
6
4
4
61
75
Total
887
5,260.7
1,851
852
5,261.2
1,816
878
4,807.2
1,759
(a) Includes Eni’s share of equity-accounted equities.
(b) Includes volumes of hydrocarbons consumed in operations (119,97 and 88 kboe/d in 2018, 2017 and 2016, respectively).
Eni Annual Report 2018OPERATING REVIEW | EXPLORATION & PRODUCTION
40
PRODUCTIVE WELLS
In 2018, oil and gas productive wells were 8,170 (2,836.6 of which
represented Eni’s share). In particular, oil productive wells were
6,640 (2,070.1 of which represented Eni’s share); natural gas
productive wells amounted to 1,530 (766.5 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)
2018
Oil wells
Natural gas wells
Gross
202.0
477.0
592.0
1,194.0
2,747.0
200.0
955.0
270.0
3.0
6,640.0
Net
157.0
86.5
242.8
508.3
550.4
55.1
336.7
132.1
1.2
2,070.1
Gross
479.0
135.0
116.0
147.0
181.0
167.0
284.0
21.0
1,530.0
Net
415.9
65.3
63.2
48.3
23.0
62.0
81.7
7.1
766.5
(a) Includes 1,445 gross (420.8 net) 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 ACTIVITIES
In 2018, a total of 24 new exploratory wells were drilled (15.6 of
which represented Eni’s share), as compared to 25 exploratory
wells drilled in 2017 (15.9 of which represent Eni’s share) and
16 exploratory wells drilled in 2016 (10.2 of which represented
Eni’s share).
The following tables show the number of net productive, dry 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 62% (66% net to Eni) as compared to
60% (52% net to Eni) in 2017 and 50% (50% net to Eni) in 2016.
Exploratory Well Activity
2018
Net wells completed(a)
2017
2016
Wells in progress at Dec. 31(b)
2018
Italy
Rest of Europe
North Africa
Egypt
Sub-Saharan Africa
Kazakhstan
Rest of Asia
Americas
Australia and Oceania
(units)
productive
1.8
dry(c)
productive
dry(c)
productive
0.5
0.5
1.5
2.6
5.1
1.2
0.5
2.5
2.9
0.5
7.6
1.3
5.4
0.3
0.1
0.5
5.5
0.1
7.0
6.2
1.7
0.4
2.2
4.0
10.1
dry(c)
1.0
0.4
1.0
0.8
1.1
0.9
1.0
6.2
gross
1.0
12.0
8.0
11.0
31.0
6.0
8.0
2.0
1.0
80.0
net
0.5
3.5
7.0
8.9
15.1
1.0
2.5
1.5
0.3
40.3
(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 ACTIVITIES
In 2018, a total of 209 development wells were drilled (80.2 of
which represented Eni’s share) as compared to 178 development
wells drilled in 2017 (90.7 of which represented Eni’s share)
and 296 development wells drilled in 2016 (118.7 of which
represented Eni’s share).
The drilling of 38 development wells (10.6 of which represented
Eni’s share) is currently underway.
The following tables show 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
2018
Net wells completed(a)
2017
2016
Wells in progress at Dec. 31
2018
(units)
productive
dry(b)
productive
dry(b)
productive
dry(b)
gross
Italy
Rest of Europe
North Africa
Egypt
Sub-Saharan Africa
Kazakhstan
Rest of Asia
Americas
Australia and Oceania
3.0
2.8
9.6
30.7
7.3
0.9
21.9
2.3
0.8
79.3
0.3
0.5
0.1
0.9
2.6
2.7
5.1
49.7
8.6
1.2
15.0
3.1
88.0
0.2
2.3
0.2
4.0
5.6
6.2
32.4
21.2
4.6
31.6
9.9
2.7
115.5
0.7
0.5
0.2
0.5
1.3
3.2
net
1.3
1.4
2.1
2.5
0.3
3.0
16.0
3.0
5.0
6.0
1.0
7.0
38.0
10.6
(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.
ACREAGE
In 2018, Eni performed its operations in 43 Countries located
in five continents. As of December 31, 2018, Eni’s mineral
right portfolio consisted of 902 exclusive or shared rights
of exploration and development activities for a total acreage
of 406,505 square kilometers net to Eni (414,918 square
kilometers net to Eni as of December 31, 2017). Developed
acreage was 28,386 square kilometers and undeveloped acreage
was 378,119 square kilometers net to Eni.
In 2018, main changes derived from: (i) new leases mainly
in the United Arab Emirates, Indonesia, Lebanon, Morocco,
Mexico, Norway and the United States for a total acreage
of approximately 31,000 square kilometers; (ii) the total
relinquishment of licenses mainly in Australia, China, Egypt,
Indonesia, Morocco, Pakistan, Russia, the United Kingdom and
Ukraine covering an acreage of approximately 35,000 square
kilometers; (iii) interest increase mainly in Angola and Ireland
for a total acreage of approximately 2,000 square kilometers;
and (iv) partial relinquishment in Cyprus, Gabon and Indonesia
or interest reduction mainly in Egypt, Norway and Pakistan for
approximately 6,400 square kilometers.
In October 2018, Eni submitted to the relevant Authorities
of Portugal the documentation required for voluntary release
of exploration concessions, with effective date as of January
31, 2019.
Eni Annual Report 2018OPERATING REVIEW | EXPLORATION & PRODUCTION
42
Oil and natural gas interests
December 31, 2017
December 31, 2018
)
a
(
e
g
a
e
r
c
a
t
e
n
l
a
t
o
T
EUROPE
Italy
Rest of Europe
Croatia
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
Liberia
Mozambique
Nigeria
South Africa
Other Countries
ASIA
Kazakhstan
Rest of Asia
China
India
Indonesia
Iraq
Lebanon
Myanmar
Oman
Pakistan
Russia
Timor Leste
Turkmenistan
United Arab Emirates
Vietnam
Other Countries
AMERICAS
Ecuador
Mexico
Trinidad & Tobago
United States
Venezuela
Other Countries
AUSTRALIA AND OCEANIA
Australia
51,206
16,380
34,826
987
17,967
1,909
614
2,117
3,182
5,805
2,245
161,981
25,797
1,141
13,294
9,804
1,558
9,192
126,992
4,367
1,471
5,283
579
2,905
43,948
585
978
7,370
26,202
33,304
184,029
1,543
182,486
7,154
5,244
22,889
446
13,558
77,146
7,401
20,862
1,230
180
23,132
3,244
6,641
1,985
1,146
66
1,052
1,066
1,326
11,061
11,061
t
s
e
r
e
t
n
i
f
o
r
e
b
m
u
N
317
140
177
6
2
1
106
3
57
2
261
64
42
11
1
10
53
144
58
25
4
3
3
6
6
34
1
4
61
7
54
7
1
13
1
2
4
1
12
2
1
1
3
5
1
252
1
8
230
6
7
11
11
l
d
e
p
o
e
v
e
d
s
s
o
r
G
)
b
(
)
a
(
e
g
a
e
r
c
a
s
s
o
r
G
l
d
e
p
o
e
v
e
d
n
u
)
a
(
e
g
a
e
r
c
a
s
s
o
r
g
l
a
t
o
T
)
a
(
e
g
a
e
r
c
a
l
d
e
p
o
e
v
e
d
t
e
N
)
b
(
)
a
(
e
g
a
e
r
c
a
l
d
e
p
o
e
v
e
d
n
u
t
e
N
)
a
(
e
g
a
e
r
c
a
)
a
(
e
g
a
e
r
c
a
t
e
n
l
a
t
o
T
13,757
9,962
3,795
2,886
909
46,263
8,846
3,283
1,963
3,600
5,423
31,994
8,200
1,430
226
22,138
13,024
2,391
10,633
77
2,943
1,074
3,390
200
2,949
4,419
1,985
1,173
1,261
1,140
1,140
58,376
8,871
49,505
22,790
4,890
1,228
9,630
4,547
3,719
2,701
258,232
48,760
187
24,673
23,900
10,480
198,992
13,241
1,320
4,107
1,127
4,010
50,677
3,911
8,631
65,505
46,463
285,289
3,890
281,399
5,215
13,110
27,230
3,653
24,080
90,760
11,486
53,930
1,538
5,020
30,777
14,600
12,543
4,387
1,949
1,543
4,664
4,611
4,611
72,133
18,833
53,300
22,790
4,890
1,228
12,516
4,547
4,628
2,701
304,495
57,606
3,470
26,636
23,900
3,600
15,903
230,986
21,441
2,750
4,107
1,353
4,010
50,677
3,911
30,769
65,505
46,463
298,313
6,281
292,032
5,292
13,110
30,173
1,074
3,653
24,080
90,760
14,876
53,930
1,538
200
7,969
30,777
14,600
16,962
1,985
4,387
3,122
2,804
4,664
5,751
5,751
9,409
8,303
1,106
492
614
11,844
3,640
1,124
958
1,558
2,018
6,186
1,064
843
100
4,179
3,368
442
2,926
13
1,198
446
872
180
217
3,056
1,985
574
497
709
709
36,923
6,684
30,239
17,111
1,909
614
2,136
3,182
3,404
1,883
153,855
30,292
31
12,336
17,925
3,230
120,333
4,239
628
4,107
479
2,905
43,948
978
3,543
26,202
33,304
178,046
1,101
176,945
5,215
5,244
22,571
1,461
13,558
77,146
4,914
17,975
1,230
1,255
23,132
3,244
6,247
3,000
1,617
569
1,061
3,048
3,048
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
Total
414,918
902
78,603
619,051
697,654
28,386
378,119
406,505
(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
REST OF
EUROPE
(1926)
Operated
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 (60.77%)
Sicily Region
Gela (100%), Tresauro (45%), Giaurone (100%), Fiumetto (100%),
Prezioso (100%) and Bronte (100%)
Norway(a)
(1965)
Operated
Goliat (45.24%), Marulk (13.92%), Balder & Ringhorne (69.6%) and Ringhorne East (53.85%)
United
Kingdom
Non-operated Åsgard (10.31% ), Kristin (5.74%), Heidrun (3.60%), Mikkel (10.37%), Tyrihans (4.32%),
(1964)
Operated
Morvin (20.88%), Great Ekofisk Area (8.62%), Boyla (13.92%), Brage (8.53%) and Snorre (0.7%)
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
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%), Area F
(Block 118 - 50%) 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%), Melehia (76%), North Port Said (Port Fouad - 100%),
Temsah (Tuna, Temsah and Denise - 50%), Baltim (50%), Ras Qattara (El Faras e Zarif - 75%),
West Abu Gharadig (Raml - 45%), Ashrafi (50%) and North Razzak (100%)
Non-operated Ras el Barr (Ha’py and Seth - 50%) and South Ghara (25%)
SUB-SAHARAN
AFRICA
Angola
(1980)
Operated
Block 15/06 (36.84%)
Congo
(1968)
Non-operated Block 0 (9.8%), Development Areas in the Block 3 and 3/05-A (12%), Development Areas
in the Block 14 (20%), Lianzi Development Area in the Block 14 K/A IMI (10%)
and Development Areas in the Block 15 (20%)
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%)
Operated
Ghana
Nigeria
Non-operated Pointe-Noire Grand Fond (35%) and Likouala (35%)
(2009)
Operated
Offshore Cape Three Points (44.44%)
(1962)
Operated
OMLs 60, 61, 62 and 63 (20%), OML 125 (100%) and OPL 245 (50%)
Non-operated(d) OML 118 (12.5%) and OML 116 service contract
KAZAKHSTAN(b)
(1992)
Non-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
United States
(1968)
Operated
Gulf of Mexico
Allegheny (100%), Appaloosa (100%), Pegasus (85%), Longhorn (75%),
Devils Towers (75%) and Triton (75%)
Alaska
Nikaitchuq (100%)
Non-operated Gulf of Mexico
Alaska
Texas
Europa (32%), Medusa (25%), Lucius (8.5%), K2 (13.4%), Frontrunner
(37.5%) and Heidelberg (12.5%)
Oooguruk (30%)
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. Those 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 2018OPERATING 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 Western 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) within the
agreement with the Municipality of Ravenna, planned activities in the
field of the environmental protection projects.
In addition, during the first half of 2018, as planned, school-work
alternation projects and first-level apprenticeship were completed.
In the Val d’Agri concession (Eni operator with a 60.77% interest) a
digital transformation program of the Viggiano Oil Center was launched.
Leveraging on the digital technologies developed by Eni, the project
plans to upgrade and increase monitoring processes of plant and
environmental safety in site the to improve operational performance.
During the year, five projects were completed, reaching a total of 35
projects of the 42 planned projects as part of the 2014 Addendum
to the agreement memorandum with the Basilicata Region, which
provides environmental and social initiatives as well as sustainable
development programs.
In the first half of the year, as planned, school-work alternation
projects and first-level apprenticeship were completed.
Activities defined by the Gas Agreement progressed with a grant to
support the energy consumption in the Municipalities of Val d’Agri
and for energy efficiency programs.
Following the Memorandum of Understanding for the Gela area,
signed with the Ministry of Economic Development in November
2014, the Argo and Cassiopea offshore (Eni’s interest 60%)
development projects progressed.
The optimized project, to reduce significantly the environmental
impact, 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, within the framework of sustainable local development
programs defined by Memorandum of Understanding and in
agreement with the Municipality of Gela and the Sicily Region were:
(i) school-work alternation projects, first-level apprenticeship,
programs to reduce school drop-out as well as university scholarship
progressed; and (ii) signed an agreement for the project “Safety
food in Gela” to support vulnerable groups through a public-private
partnership between Eni, the Municipality of Gela and the Rete del
Banco Alimentare NGO.
REST OF EUROPE
Norway In December 2018 it was finalized the business combination
between Point Resources AS and Eni Norge AS, fully-owned by
HitecVision and Eni respectively, with the creation of Vår Energi AS,
an equity-accounted joint venture. The exchange rate of shares was
established so that Eni and the Point Reources shareholders would
retain participation interests of 69.6% and 30.4% respectively, in the
combined entity. The governance of the new entity is designed to
establish joint control of the two shareholders over the combined entity.
OPERATING REVIEW | EXPLORATION & PRODUCTION 45
The transaction intends to strengthen Eni’s operational structure
in the Country and the increase/diversification of the asset
portfolios which will ensure a production growth higher than the
current portfolio.
The combined entity will be a leading Norwegian exploration &
production company, built on the existing organizations and
leveraging on complementary strengths.
The portfolio of the combined company will have 17 producing oil and
gas field with a wide geographical reach, from the Barents Sea to the
North Sea, thanks to the entry of new assets, including the fields in
production of Balder & Ringhorne (Eni’s interest 69.6%), Ringhorne
East (Eni’s interest 53.85%), Boyla (Eni’s interest 13.92%), Brage
(Eni’s interest 8.53%) and Snorre (Eni’s interest 0.7%).
The company will have reserves and resources of more than 1,250
mmboe. Production is expected to achieve 250 kboe/d in 2023 after
developing more than 500 mmboe in ten existing assets, with a
breakeven price of less than 30 $/bbl.
In total, the company plans to invest more than $8 billion over the
next five years to bring these projects on stream, revitalize older
fields and explore for new resources.
Finally, Eni will retain a first offer right in case the Norwegian private
equity funds, managed by HitecVision, decide to divest their interest
in the venture.
In 2019 Vår Energi awarded 13 exploration licenses: (i) the
operatorship of two licenses in the North Sea and of two licenses in
the Barents Sea; and (ii) the interest of five licenses in the North Sea
and of four licenses in the Norway Sea.
Exploration activities yielded positive results with: (i) delineation
well of the Cape Vulture oil and gas discovery in the PL 128/128D
license (Eni’s interest 8%), nearby to the production facilities of the
Norne field (Eni’s interest 4.8%). The results of the well confirm the
commerciality of the discovery with recoverable volumes between
50 and 70 million boe; (ii) new oil discovery in the PL 532 license
(Eni’s interest 20.88%). The well is located nearby to the Johan
Castberg developing project in the area and Eni estimates the
resources in place of oil and gas to be between 50 and 60 million
boe; (iii) the Goliat West oil well in the PL 229 license (Eni’s interest
45.24%), increasing the estimated reserves of the Goliat production
field; and (iv) an oil and gas discovery in the PL 869 which is
participated by Vår Energi AS with a 20% interest.
Development activities concerned: (i) the Trestakk project (Eni’s
interest 5,5%), with start-up expected in 2019 and a production of 4
million boe net to Eni; and (ii) the Johan Castberg development project
which was sanctioned in June 2018. Start-up is expected in 2022.
NORTH AFRICA
Algeria In April 2018, Eni signed a framework agreement with
Sonatrach to revamp exploration and development program in the
Berkine area and to continue a collaboration in the R&D sector. In
particular: (i) in July 2018 defined an agreement for upgrading
existing facilities of the BRN fields in the Block 403 (Eni operator
with a 50% interest) and of the MLE fields in the Block 405b (Eni
operator with a 75% interest) leveraging on synergies with the new
forthcoming facilities. The agreement also includes the construction
of a pipeline to link the BRN fields with MLE assets, targeting to
transform the area in a gas hub; and (ii) in October 2018 signed
an agreement to assign to Eni a 49% interest in the Sif Fatima II,
Zemlet El Arbi and Ourhoud II concessions, in the North Berkine
basin. Management plans an exploration campaign and fast-track
development of the estimated reserves of 75 mmboe net to Eni. The
production start-up is planned in the third quarter of 2019 leveraging
on the completion of the BRN-MLE pipeline that will link the BRN
associated gas as well as associated gas and condensates of the
Berkine North development project to the MLE treatment facilities.
In addition, Eni and Total signed two partnership agreements for
an exploration campaign in the offshore Algeria. In particular, in
December 2018, two exploration permits were assigned to launch a
seismic data acquisition in 2019.
Development activities concerned: (i) production optimization at the
ROM North (Eni’s interest 35%) and ROD (Eni’s interest 55%) operated
fields as well as in the non-operated Block 404 (Eni’s interest
12.25%); (ii) drilling activities in the Block 405b at the CAFC Oil and
MLE projects, as well as upgrading activity of existing treatment
facilities; and (iii) progress in the development program of the El
Merk field in the Block 208 (Eni’s interest 12.25%) with the drilling of
production and water injection wells.
Libya In 2018, Eni finalized an agreement with NOC oil state company
and BP to award a 42.5% interest and the operatorship in the BP
contractual areas, in particular in the onshore areas A and B and in
the offshore area C. The agreement provides for a revamp exploration
and development activities in the Country leveraging on Eni’s
facilities existing in the areas. In addition, the agreement strengthens
the partnership in the social development initiatives through
implementation of education and training programs.
During the year, development activities concerned: (i) production
start-up of the Bahr Essalam Phase 2 offshore project (Eni’s interest
50%) where the planned activities progressed and the completion
is expected in the second quarter of 2019. The development plan
provided for drilling ten wells, out of which seven were completed
and started up in 2018, as well as upgrading the existing facilities to
increase production capacity; (ii) upgrading of gas treatment plants
at the Mellitah area (Eni’s interest 50%) and Sabratha platform (Eni’s
interest 50%); and (iii) production optimization plan in the Wafa
field (Eni’s interest 50%). The activity provided for drilling additional
wells and the construction of new compression units. In particular,
the infilling wells campaign started in 2018: a first gas well was
completed in November 2018 and a second one in March 2019. The
project is expected to be completed in 2019.
Following the Memorandum of Understanding signed in 2017 to
promote health and education initiatives of local communities,
two starting programs were defined: (i) support to the local Health
Authorities, in particular with a renovation program of the hospital in
the Jalo area, technical assistance and medical training initiatives;
and (ii) the construction of a pipeline for the desalination plant in the
Zuara area to provide drinking water to local communities.
In 2018, Eni signed a Memorandum of Understanding with the GECOL
national power company and NOC oil state company that includes
the start-up of a rehabilitation project for power plants to support
access to energy for local communities. In addition, other Eni’s
programs to support local communities progressed. In particular:
(i) initiatives in the field of health, water and access to energy
nearby to the Bu-Attifel (Eni’s interest 50%) and the El Feel (Eni’s
interest 33.3%) production areas; (ii) health and oil & gas training
program; and (iii) renovation and construction of facilities for social
purposes as well as drugs supplies.
Eni Annual Report 2018OPERATING REVIEW | EXPLORATION & PRODUCTION 46
EGYPT
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 (Eni’s interest 100%);
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.
Exploration activities yielded positive results with: (i) the Faramid-
S1X gas well in the East Obayed concession (Eni’s interest
100%); (ii) the A-2X and B1-X oil discoveries and the A-1X gas and
condensates discovery in the South West Meleiha concession; and
(iii) the Nour-1 gas well in the Nour exploration license.
In June 2018, Eni completed the disposal of a 10% interest of the
Zohr project (Eni’s interest 50%) to Mubadala Petroleum, for a cash
consideration of $934 million.
In August 2018, Egyptian Authority approved the following
agreements: (i) Eni was awarded an 85% interest in the Nour
exploration license in the eastern offshore Nile Delta. In December
2018, Eni divested a 20% and 25% interest of Nour license to
Mubadala Petroleum and BP, respectively. Currently Eni holds
40% interest; (ii) ten years extension from 2021 of the Nile Delta
concession (Eni’s interest 75%) which includes Abu Madi West
concession with Nooros producing field; (iii) an extension of
exploration campaign in the El Qar’a permit (Enis’ interest 75%),
which is located in the Great Nooros sizeable producing area; (iv)
five years extension of the Ras Qattara concession (Eni’s interest
75%) in the western desert; and (v) an extension of the Faramid
development lease (Enis’ interest 100%).
In September 2018, one-year earlier than scheduled, the Zohr
project achieved the targeted production plateau of 365 kboe/d
(110 kboe/d net to Eni) with the completion of the drilling activities
and the construction and commisioning of the planned four gas
treatment units onshore in addition to the one started at the end of
2017, which increased available treatment capacity to more than 2.1
bcf/d. Management plans to step up the production plateau to 3.2
bcf/d during 2019 by building and commissioning other three gas
treatment units and by drilling three additional production wells to
reach 13 production wells.
As of December 31, 2018, the aggregate development costs incurred
by Eni for the Zohr project capitalized in the financial statements
amounted to $4.3 billion (€3.8 billion at the EUR/USD exchange rate
of December 31, 2018). The capital expenditures of the four-year
plan for the production ramp-up at the Zohr field will be financed
with the operating cash-flow at the Eni Brent marker scenario.
As of December 31, 2018, Eni’s proved reserves booked for the Zohr
field amounted to 782 mmboe.
Development activities concerned: (i) the Baltim South West project
(Eni operator with a 55% interest) in the offshore of the Country. The
project sanctioned in 2018 and start-up is expected during 2019; (ii)
the completion and start-up of two additional productive wells of the
Nooros field (Eni operator with a 75% interest) and the construction
of a pipeline for transporting gas to the treatment plan of El Gamil.
The completion of the activities is expected in 2019; and (iii) infilling
activities and production optimization in the operated Sinai (Eni’s
interest 100%), Meleiha (Eni’s interest 76%) and Ras Qattara (Eni’s
interest 75%) concessions. In particular, the water reinjection project
is completed in the Sinai area, achieving the zero water discharge.
Within the social responsibility initiatives are currently being
implemented the programs defined by the MoU signed in 2017. The
agreement, which integrates the development activities of the Zohr
project, defines two action programs, to be implemented in four
years. The first included the renovation of the El Garabaa hospital,
located nearby the Zohr onshore production facilities and the supply of
necessary medical equipment. The planned activities were completed
in May 2018. 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 the local Authorities three main areas:
(i) aquaculture and fisheries, in particular the construction of a fish
district. The activities started up during 2018; (ii) health care projects.
A first project was defined in agreement with the Ministry of Health
and includes the construction of a Primary Health Care Center which
will provide health services to approximately 60,000 people in the
Port Said area. The completion is expected in 2019. In addition, the
project provides for the construction of the identified facilities and also
further initiatives of health training and prevention; and (iii) programs
to support youth, in particular the construction of a youth center with
completion expected in 2019.
SUB-SAHARAN AFRICA
Angola Exploration activities yielded positive results with: (i) the
Kalimba and Afoxé oil discoveries in the East Hub project area in the
Block 15/06 (Eni operator with a 36.84% interest) with an estimated
resources of 400-500 mmbbl of oil in place; and (ii) the Agogo oil
discovery in the West Hub project area in the Block 15/06 with an
estimated resources of 450-650 mmbbl of oil in place.
The development of the discoveries will leverage on synergies with
existing facilities.
In November 2018, Eni signed an amendment of the Block 15/06 PSA
contract that defines an additional exploration acreage in the western
area of the block. The agreement confirms Eni’s near-field strategy
for a fast-track development of exploration successes leveraging on
existing production facilities.
Development activities mainly concerned the two producing projects
in the Block 15/06. In particular, activity of the West Hub project
included: (i) production ramp-up of the Ochigufu field was achieved
with a production plateau of 25 kbbl/d; and (ii) production start-up of
the Vandumbu field. In the East Hub project development activities
concerned: (i) production start-up of UM8 field with the linkage to
existing FPSO in the area; (ii) upgrading of certain production facilities;
and (iii) the Cabaça North & Cabaça South-East UM4/5 projects were
sanctioned; the development plan provides for the drilling of three
productive wells, two water injection wells and the connection to the
existing production facilities in the area. Start-up is expected in 2021.
Planned drilling activities were completed at the Mafumeira Sul
producing field 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. In particular, activities progressed with: (i) access to
energy from renewable sources and to water; (ii) health initiatives
through awareness projects of local communities, staff training
programs, energy supplies for the Health Centers and Hospitals, also
in the Luanda area; and (iii) scholarship programs.
In 2018 activities concerned: (i) start-up of initiatives to support the
agricultural development by means of the training centers; (ii) mine
OPERATING REVIEW | EXPLORATION & PRODUCTION 47
removal programs of certain areas to increase safety, to guarantee
land for agricultural use and to improve resilience and stability
of the local communities; and (iii) the “Luanda refinery reliability
improvement and gasoline production” project. The activities include
the development of specific solutions to improve the reliability of
the Luanda refinery, to increase the fuel production through the
installation of new production units, processes optimization and
staff training. During the year a first unplanned maintenance was
performed and the training program started.
Congo Development activity carried out in 2018 was related to:
(i) the Nené Marine Phase 2A producing project in the Marine XII
block (Eni operator with a 65% interest) with the completion of
drilling activities and the installation of a sealine for the connection
to the Litchendjili field production platform in the Marine XII block;
(ii) the completion of engineering activities of the Nené Marine
Phase 2B project. The project was sanctioned in December 2018;
(iii) activities to increase the power generation of the CEC plant
(Eni’s interest 20%) up to 170 MW. Additional gas supply will be
ensured by the production of the Marine XII block; and (iv) the
water reinjection project of the Loango (Eni’s interest 42.5%) and
Zatchi (Eni’s interest 55.25%) operated production fields.
The activities of the second phase of the Project Integrated
Hinda (PIH) progressed, aiming to improve life condition of
local communities. The project includes several initiatives to
support socio-economic development, access to water, access to
energy, education and health service. In particular, in 2018, the
programs concerned: (i) the completion of the CATREP agricultural
development project with a training program of 14 agricultural
cooperatives, that was supported also by the World Food Program;
(ii) renovation and construction of multicultural centers; (iii)
scholarship programs, in particular in the Pointe Noire area through
the supply of educational material and renovation initiatives; and
(iv) programs to strengthen the Primary Health Care services at
the Health Centers and others operating in the area, in particular
in the maternal and child sphere. In addition, the construction of a
training and research center on renewable energy progressed in
Oyo, in the north of the Country.
Ghana In 2018, the non-associated gas production started up at the
operated Offshore Cape Three Points (OCTP) project (Eni’s interest
44.44%). The gas production is sent to an onshore treatment plant to
feed the national grid.
The OCTP project is the only non-associated gas development project in
deep water entirely dedicated to the domestic market in Sub-Saharan
Africa. This project will ensure at least 15 years of reliable gas supply
with an affordable price, significantly supporting the access to
energy and economic development of the Country. The project has
been developed in compliance with the highest environmental
requirements, zero gas flaring and produced water reinjection.
Eni progressed its commitment to improve the living condition of
local communities, with training, economic diversification, acces to
water and health services initiatives. In 2018, primary education,
waste management and access to water projects started up in the
western area of the Country. In particular, a well was drilled and a
treatment and purification water-system was completed to supply
water for approximately 5,000 people located in the Bakanta, Krisan
and Sanzule communities.
Within the partnership with United Nations Development Programme,
certain activities are being designed to reduce the CO2 emissions in
the medium-term by means of combating deforestation, access to
energy and energy efficiency programs.
Mozambique In October 2018, Eni signed the contract for the
exploration and development rights of the offshore block A5-A, in the
deep offshore of Zambesi. Eni was awarded the operatorship of the
block with a 59.5% interest.
In March 2019, Eni signed a farm out agreement with Qatar Petroleum
to divest a 25.5% interest in the block A5-A. The transaction is
subjected by approval of the relevant Authority.
The development activities of the Area 4 (Eni’s interest 25%) in the
offshore Mozambique concerned the Coral field, operated by Eni,
and the Mamba Complex discoveries where Eni operates upstream
development phase and Exxon Mobil lead the construction and
operation of natural gas liquefaction facilities onshore.
Development activities of the Coral South project provide for the
installation of a floating unit for the treatment, liquefaction and
storage of natural gas (FLNG) with a capacity of approximately 3.4
mmtonnes/y fed by 6 subsea wells and start-up expected in 2022.
The LNG produced will be sold by Eni and its partners in Area 4 (CNPC
and Exxon Mobil via the Mozambique Rovuma Venture SpA operating
company and others) to BP under a long-term contract for a period of
twenty years with an additional ten years’ option.
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 (Andarko). The development project will
include also a part of non-straddling reserves. 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 July 2018, the plan of development (PoD) was submitted to the
relevant Authorities for their initial review. The activities progressed
with the finalization of the PoD, of preliminary long-term agreements
for the purchase of LNG volumes and the project financing. The Final
Investment Decision (FID) is expected in 2019 with start-up in 2024.
In 2018 , Eni’s programs to support the local communities of the
Country progressed with, in partcicular: (i) the scholarship programs
in Pemba, also by means of ordinary and extraordinary schools
maintenance activities and training initiatives also with an oil &
gas training programs; and (ii) health care initiatives, coordinated
with the Country’s health Authorities, in the Maputo, Pemba and
Palma area, by means of specific initiatives on prevention, facilities
constructions and medical equipment supplies, particularly in the
Cabo Delgado area.
Nigeria Exploration activities yielded positive results with the EPU-05
deep offshore gas discovery in the Gbaran-Kolo Creek-Epu (Eni’s
interest 5%) area.
Development activities mainly included: (i) workover and rigless
activities to support current production as well as maintenance and
restoration of damaged facilities due to sabotage and bunkering in
the operated OML 60, 61, 62 and 63 blocks (Eni’s interest 20%); (ii)
the completion of the water injection project of the Ebocha field in
the OML 61 block, achieving a produced water reinjection capacity
of approximately 30 kbbl/day; (iii) the phase 2 activities of Okpai
Eni Annual Report 2018OPERATING REVIEW | EXPLORATION & PRODUCTION 48
plant to double the installed power capacity in the OML 60 block;
(iv) drilling activities to increase production and workover activities
to mitigate mature field decline in the OML 118 block (Eni’s interest
12.5%) and in the operated OML 125 block in the Abo field (Eni’s
interest 100%); and (v) associated gas program of Forkados Yokri
Integrated Project in the OML 43 block (Eni’s interest 5%) as well as
Gbaran phase 2A/2B and SSAGS project in the OML 28 block (Eni’s
interest 5%). Gas production will be sold to the local market.
In February 2018, Eni signed with the Food and Agriculture
Organization (FAO) a collaboration agreement 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.
Eni’s programs to support local communities progressed with: (i)
acces to energy and to water 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.
Eni holds a 10.4% interest in the Nigeria LNG Ltd joint venture,
which runs the Bonny gas liquefaction plant located in the Eastern
Niger Delta. The plant is operational, with a treatment capacity of
approximately 1,236 bcf/y of feed gas and a production capacity of
22 mmtonnes/y of LNG.
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 2018, the Bonny liquefaction
plant processed approximately 1,130 bcf.
LNG production is sold under long-term contracts and exported to
the United States, Asian and European markets by the Bonny Gas
Transport fleet, wholly owned by Nigeria LNG.
KAZAKHSTAN
Kashagan In 2019, Experimental Program development of the
Kashagan field (Eni’s interest 16.81%) is expected to lead to plateau oil
production capacity of about 370 kbbl/d, on a 100% basis. Additional
phases of development are being studied, which contemplate
increasing gas injection capacity, the conversion of production wells
into injection wells and the upgrading of the existing facilities.
Within the agreements with local Authorities, training program
progressed for Kazakh resources in the Oil & Gas sector, in addition
to the realization of infrastructures with social purpose.
As of December 31, 2018, the aggregate costs incurred by Eni for the
Kashagan project capitalized in the financial statements amounted to
$9.9 billion (€8.6 billion at the EUR/USD exchange rate of December
31, 2018). This capitalized amount included: (i) $7.3 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.
As of December 31, 2018, Eni’s proved reserves booked for the
Kashagan field amounted to 614 mmboe, slightly decreased from 2017.
Karachaganak Within the gas treatment expansion projects of
the Karachaganak field (Eni’s interest 29.25%), the Karachaganak
Process Center Debottlenecking project was sanctioned. Activities
progressed with completion expected in 2020. Additional reinjection
capacity will be ensured by installing a new reinjection facility in
addition to the existing ones.
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, 2018, Eni’s proved reserves booked for the
Karachaganak field amounted to 452 mmboe, reporting a decrease of
78 mmboe from 2017 mainly due to an increased marker Brent price
used in the reserves estimation process.
REST OF ASIA
Indonesia Exploration activities yielded positive results with the
Merakes East discovery in the operated East Sepinggan block (Eni’s
interest 85%).
In May 2018, Eni was awarded a 100% interest in the East Ganal
exploration block in the deep offshore Kutei area nearby to the
operated Muara Bakau block (Eni’s interest 55%).
In 2018, within the portfolio rationalization, Eni divested entire
interest in the Sanga Sanga permit.
Development activities concerned the offshore Merakes gas project
in the operated East Sepinggan block. In December 2018, the
development plan was sanctioned by the relevant Authorities. The
project provides for the drilling of five subsea wells, which will be
linked to the Floating Production Unit (FPU) of the Jangkrik producing
field (Eni operator with a 55% interest). Natural gas production is
processed by the FPU and then delivered by pipeline to the onshore
plant, which is linked to the East Kalimantan transport system to
feed Bontang liquefaction plant or will be sold on a spot basis in the
domestic market. Start-up is expected in 2020.
Ongoing initiatives and projects progressed in the field of
environmental protection, health care and educational system to
support local communities located in the operated areas of the
Eastern Kalimantan, Papua and North Sumatra.
In 2018, the following programs were launched: (i) to promote access
to energy and to water for the local communities; and (ii) training
agricultural activities. In addition, health initiatives were defined.
United Arab Emirates In 2018, assets acquisition campaign was
launched by Eni targeting to expand footprint in the Country. In
particular, the following acquisitions of exploration and production
assets in Abu Dhabi were finalized: (i) in March 2018, Eni signed
two Concession Agreements related to the acquisition of a 5%
participating interest in the Lower Zakum oil field and a 10%
participating interest in the Umm Shaif and Nasr oil, condensates and
natural gas fields, in the offshore of Abu Dhabi, for a consideration
of $875 million with duration of 40 years; (ii) in November 2018, Eni
was awarded a 25% interest of the Ghasha offshore concession with
duration of 40 years. The concession includes Hail, Ghasha, Dalma
gas fields and certain offshore fields in the Al Dhafra area. Production
start-up is expected in 2022; and (iii) in January 2019, Eni was
awarded 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 two appraisal wells in the Block 2.
In January 2019 Eni was awarded three onshore exploration
concessions in the Emirate of Sharjah: (i) the operatorship with a
75% interest in the concession Area A and C; and (ii) a 50% interest in
the concession Area B. The exploration commitment of the first phase
OPERATING REVIEW | EXPLORATION & PRODUCTION 49
includes the drilling of one exploration well and exploration studies in
concessions Area A and B as well as exploration studies in Area C.
AMERICAS
Mexico In 2018, Eni signed the following agreements: (i) with the
Lukoil company to swap interest in three exploration licenses. In
particular, the agreement provides for Eni divests its 20% interest
in Area 10 (Eni’s interest 100%) and Area 14 (Eni’s interest 60%)
licenses and purchases a 40% interest in Area 12 license operated
by Lukoil; and (ii) to divest its 35% interest of the Area 1 (Eni’s
interest 100%) to Qatar Petroleum Company.
The agreements are subject to approval by the relevant Authorities.
Furthermore, in 2018, Eni was awarded the operatorship with a 65%
interest of the Area 24 license and with 75% of the Area 28 license.
In July 2018, the plan of development for the Amoca, Mitzón and
Tecoalli discoveries, located in the Area 1, was approved by the
Mexican Authorithies. The phased approach for the development
plan includes an early production start-up in 2019 through the
installation of a production platform and the realization of facilities
to connect the platform to an onshore existing treatment plant,
with a production of 8 kbbl/d. The full field development envisages a
phased installation of three additional platforms and a FPSO, which
will increase the production capacity up to 90 kbbl/d in 2021.
In 2018, certain initiatives to support local communities were
implemented and held events with local stakeholders nearby to
the license areas in development of Area 1. In addition, the first
Local Development Plan was finalized, in agreement with the
local Authorities, concerning the future programs to support the
communities.
United States In August 2018, Eni was awarded a 100% interest of
124 licenses in Alaska. The licenses are located in the the Eastern
North Slope of Alaska, a high mineral potential area, nearby to the
existing production facilities.
In December 2018, Eni signed an agreement to purchase of a 70%
interest and the operatorship of the Oooguruk field, where Eni
already holds 30% stake. The agreement has been finalized in 2019.
Development activities concerned the Lucius Subsequent Development
project (Eni’s interest 8.5%) with the drilling and completion of three
submarine productive wells, which will be linked to the production
platform of the Lucius field and upgrading of existing facilities.
CAPITAL EXPENDITURE
Capital expenditure of the Exploration & Production segment
(€7,901 million) concerned mainly development of oil and gas
reserves (€6,506 million) directed mainly outside Italy, in
particular in Egypt, Ghana, Norway, Libya, Nigeria, Congo and Iraq.
Development expenditure in Italy in particular concerned sidetrack
and workover activities in mature fields.
Acquisition of proved and unproved properties of €869 million
concerned the entry bonuses in the Concession Agreement of the
Lower Zakum and Umm Shaif and Nasr producing fields as well as in
the Ghasha offshore concession, in the United Arab Emirates.
Exploration expenditure (€463 million) concerned mainly the United
States, Egypt, Mexico, the United Arab Emirates and Indonesia.
In 2018 overall expenditure in R&D amounted to €96 million (€83
million in 2017). A total of 10 new patents applications were filed.
Capital expenditure
Acquisition of proved and unproved properties
Egypt
Sub-Saharan Africa
Rest of Asia
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
(€ million)
2018
869
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
2017
5
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
2016
2
2
417
11
42
270
30
57
7
7,770
407
590
747
1,700
2,176
707
1,213
220
10
65
8,254
Change
864
% Ch.
..
(5)
869
21
(4)
(134)
(35)
10
(3)
(3)
120
70
(730)
120
201
(101)
(825)
(217)
(4)
(116)
186
26
7
162
..
..
4.8
(80.0)
(72.0)
(63.6)
14.3
(12.0)
(100.0)
..
92.1
(10.1)
46.2
50.4
(16.1)
(27.2)
(11.7)
(2.0)
(17.4)
95.4
..
12.5
2.1
Eni Annual Report 2018OPERATING REVIEW | EXPLORATION & PRODUCTION
50
GAS
& POWER
ADJUSTED OPERATING
PROFIT
€ million
2016
201 7
20 18
(390)
214
543
POWER PLANTS
GHG EMISSIONS
GHG emissions/kWheq
(gCO2eq/KWheq)
Electricity produced (TWh)
398
395
2
2
6
1
0
2
2
2
7
1
0
2
402
2
2
8
1
0
2
LNG
SALES
bcm
2016
2017
2018
8.1
8.3
10.3
Performance of the year
● In 2018, the total recordable injury rate (TRIR) amounted to
0.56, increasing by 51.4% compared to 2017, as result of the
higher number of accidents (+2 events) registered among
the contractors, partly offset by the better performance in the
employees.
operating profit of €543 million, more than doubled compared
to 2017 following the restructuring of all business lines,
in particular the growth in LNG sales, power optimizations
and reduction of gas logistic costs, supported by a scenario
which allowed to enhance the flexibility of the portfolio assets.
● The greenhouse gas emissions (GHG) reported an improved
performance, approximately 2%, due to lower power generation
(down by 3.6% vs. 2017).
● Eni worldwide gas sales amounted to 76.71 bcm, down by 4.12
bcm or 5.1% compared to 2017. Eni’s sales in Italy (39.03 bcm)
increased by 4% compared to 2017.
● GHG emissions/kWheq relating to electricity production slightly
increased by 1.8% compared to the previous year due to the
higher consumption of refinery gas in place of natural gas at the
Ferrera Erbognone site.
● Electricity sales recorded an increase of 5% (up by 1.74 TWh)
compared to 2017, due to higher volumes sold to the Italian
power exchange.
● In 2018, the Gas & Power segment reported an adjusted
gas marketing activities and the power business.
● Capital expenditure amounting to €215 million mainly related the
Agreements for the purchase of LNG volumes
In order to strengthen the integration with upstream business
Eni, obtained from the partners of Area 4 joint venture, long-term
agreements for the purchase of LNG volumes. For more details see the
“Mozambique” section in the Exploration & Production segment.
LNG
CONTRACTED
VOLUMES
ELECTRICITY
SOLD
GAS SALES
IN ITALY
RETAIL CUSTOMERS
IN ITALY
AND EUROPE
8.8 MTPA
+70% vs. 2017
37.07 TWh
+4.9% vs. 2017
39.03 bcm
+4.3% vs. 2017
9.2 million
51
Energy efficiency services
In January 2019, Eni through the subsidiary Eni gas e luce SpA,
completed the acquisition of the controlling interest of SEA SpA,
an energy service company operating in the field of services
and solutions for energy efficiency. This transaction confirmed
the strategy aiming to strengthen Eni’s presence in the energy
efficiency services market, through the growth of commercial
offer with integrated and innovative solutions, mainly focused
on the industrial segment and apartment buildings.
Portfolio optimization in Europe
Completed the sale of gas distribution activities in Hungary with
a distribution network of about 33,700 kilometers and 1.2 million
of delivery points. In July 2018, in line with the planned portfolio
rationalization, Eni acquired the further 51% interest, reaching to
100% of the company “Gas Supply Company Thessaloniki-Thessalia
SA”, gas and electricity supplier in the retail market in Greece, with
approximately 300,000 customers. In March 2018, the subsidiary
Adriaplin finalized the acquisition of 100% of the company Mestni
Plinovodi, which managed gas distribution and commercialization in
11 municipalities located in the central-north and north-eastern part
of Slovenia. In May, Mestni Plinovodi was incorporated into Adriaplin
to make fully operational the synergies between the two companies.
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 9.2 million retail customers in Italy and Europe. In
particular, clients located all over Italy are 7.7 million.
In a trading environment characterized by a still decreasing
demand (down by 3% in the Italian market compared to the
previous year and down by 2% in the European Union) 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).
NATURAL GAS
SUPPLY OF NATURAL GAS
In 2018, Eni’s consolidated subsidiaries supplied 74.15 bcm
of natural gas, down by 4.13 bcm or by 5.3% from the full year
2017. Gas volumes supplied outside Italy from consolidated
subsidiaries (68.82 bcm), imported in Italy or sold outside Italy,
represented approximately 93% of total supplies, decreased by
4.41 bcm or by 6% from the full year 2017. This mainly reflected
lower volumes purchased in Russia (down by 1.85 bcm), in the
Netherlands (down by 1.25 bcm), in Algeria (down by 1.16 bcm)
and in Norway (down by 0.73 bcm), partly offset by higher
purchases in Indonesia (up by 2.32 bcm) driven by higher
availabilty of gas volumes from upstream productions and in
Qatar (up by 0.20 bcm).
Supplies in Italy (5.33 bcm) increased by 5.5% from the full year
2017 due to higher supplied gas volumes from equity production.
SUPPLIES OF ENI'S CONSOLIDATED SUBSIDIARIES
Italy
The Netherlands
Russia
Algeria
Norway
Libya
Other
7%
21%
9%
74.15 bcm
36%
5%
6%
16%
OPERATING REVIEW | GAS & POWEREni Annual Report 2018 52
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)
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
2016
6.00
27.99
12.90
4.87
9.60
8.18
2.08
3.28
5.83
1.91
76.64
82.64
1.40
(0.21)
83.83
2.48
86.31
Change
0.28
(1.85)
(1.16)
(0.21)
(1.25)
(0.73)
(0.15)
2.32
0.20
(1.23)
(0.35)
(4.41)
(4.13)
(0.23)
0.27
(4.09)
(0.03)
(4.12)
% Ch.
5.5
(6.6)
(8.8)
(4.4)
(24.0)
(9.8)
(6.4)
..
8.5
(18.2)
(15.2)
(6.0)
(5.3)
(74.2)
60.0
(5.2)
(1.1)
(5.1)
In 2018, main gas volumes from equity production derived from: (i)
Italian gas fields (3.9 bcm); (ii) certain Eni fields located in the British
and Norwegian sections of the North Sea (2.6 bcm); (iii) Indonesia (1.6
bcm); (iv) Libyan fields (1.4 bcm); and (v) the United States (0.3 bcm).
Supplied gas volumes from equity production were approximately
9.9 bcm representing 13% of total volumes available for sale.
SALES OF NATURAL GAS
In a 2018 scenario characterized by a raised competitive
pressure and a decrease in demand, natural gas sales amounted
to 76.71 bcm (including Eni’s own consumption, Eni’s share of
sales made by equity-accounted entities), down by 4.12 bcm or
5.1% from the previous year.
Gas sales by entity
Total sales of subsidiaries
Italy (including own consumption)
Rest of Europe
Outside Europe
Total sales of affiliates (net to Eni)
Rest of Europe
Outside Europe
WORLDWIDE GAS SALES
Sales in Italy (39.03 bcm) increased by 4.3% from the full year
2017 mainly driven by higher sales to spot market and volumes
sold to wholesalers and industrial segment, partly offset by
lower sales to thermoelectrical and residential segment. Sales
to importers in Italy (3.42 bcm) decreased by 12.1% from the
full year 2017 due to the lower availability of Libyan gas.
Sales in the European markets amounted to 26 bcm, a decrease
of 24.3% or 8.34 bcm from the full year 2017. Sales in the Extra
European markets increased by 3.09 bcm or 59.8% from the full
year 2017, due to higher LNG sales in Japan, Pakistan, China
and Taiwan, partly offset by lower volumes sold in South Korea
and India.
(bcm)
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
2016
83.34
38.43
40.52
4.39
2.97
1.91
1.06
86.31
Change
(3.82)
1.60
(8.52)
3.10
(0.30)
(0.29)
(0.01)
(4.12)
% Ch.
(4.9)
4.3
(23.6)
77.7
(9.1)
(13.6)
(0.8)
(5.1)
GAS SALES IN ITALY
Wholesalers
Small and medium-sized enterprises
Own consumption
Italian gas exchange and spot market
Power generation
Industries
Residential
6.11
4.20
1.50
0.79
4.79
39.03 bcm
9.15
12.49
OPERATING REVIEW | GAS & POWER
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
Hungary
UK
Turkey
France
Other
Extra European markets
WORLDWIDE GAS SALES
LNG
Europe
Outside Europe
TOTAL LNG SALES
53
(bcm)
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
2016
38.43
7.93
12.98
4.54
1.72
0.77
4.39
6.10
47.88
42.43
4.37
38.06
5.28
7.81
7.03
0.93
2.01
6.55
7.42
1.03
5.45
86.31
Change
1.60
0.79
1.68
0.37
(0.14)
(0.72)
(0.31)
(0.07)
(5.72)
(8.81)
(0.47)
(8.34)
(0.41)
(5.12)
0.23
0.01
(1.50)
(1.43)
(0.12)
3.09
(4.12)
% Ch.
4.3
9.4
15.5
8.4
(15.1)
(32.4)
(6.9)
(1.1)
(13.2)
(23.0)
(12.1)
(24.3)
(8.1)
(73.7)
4.5
0.5
(18.7)
(22.4)
(18.5)
59.8
(5.1)
(bcm)
2018
4.7
5.6
10.3
2017
5.2
3.1
8.3
2016
5.2
2.9
8.1
Change
(0.5)
2.5
2.0
% Ch.
(9.6)
80.6
24.1
In 2018, LNG sales (10.3 bcm, included in the worldwide gas sales)
increased from the full year 2017 (up by 24.1%) and mainly concerned
LNG supplied from Indonesia, Qatar, Nigeria, Oman and Algeria and
marketed in Europe, China, Japan, Pakistan and Taiwan.
POWER
Availability of electricity
Eni’s power generation sites are located in Ferrera Erbognone,
Ravenna, Mantova, Brindisi, Ferrara and Bolgiano. As of December
31, 2018, installed operational capacity of EniPower’s power
plants was 4.7 GW. In 2018, thermoelectric power generation was
21.62 TWh, down by 0.8 TWh or by 3.6% from 2017. Electricity
trading (15.45 TWh) reported an increase of 19.7% thanks to the
optimization of inflows and outflows of power.
Power sales
In 2018, power sales of 37.07 TWh increased by 4.9% from the full year
2017 and were directed to the free market (70%), the Italian power
exchange (19%), industrial sites (10%) and other (1%). Compared to
2017, power sales marketed in the free market decreased by 0.62 TWh
or by 2.3%, due to lower volumes sold to large customers (down by
2.38 TWh), middle market (down by 1.45 TWh) and small and medium-
sized enterprises (down by 0.20 TWh) partly offset by higher volumes
sold to wholesalers segment (up by 3.39 TWh).
Purchases of natural gas
Purchases of other fuels
Power generation
Steam
(mmcm)
(ktoe)
(TWh)
(ktonnes)
2018
4,300
356
21.62
7,919
2017
4,359
392
22.42
7,551
2016
4,334
360
21.78
7,974
Change
(59)
(36)
(0.80)
368
% Ch.
(1.4)
(9.2)
(3.6)
4.9
OPERATING REVIEW | GAS & POWEREni Annual Report 2018
54
AVAILABILITY OF ELECTRICITY
Power generation
Trading of electricity(a)
Total availability
Free market
Italian Exchange for electricity
Industrial plants
Other(a)
Power sales
(TWh)
2018
21.62
15.45
37.07
25.91
7.17
3.49
0.50
37.07
2017
22.42
12.91
35.33
26.53
5.21
3.01
0.58
35.33
2016
21.78
15.27
37.05
27.49
5.64
3.11
0.81
37.05
Change
(0.80)
2.54
1.74
(0.62)
1.96
0.48
(0.08)
1.74
% Ch.
(3.6)
19.7
4.9
(2.3)
37.6
15.9
(13.8)
4.9
(a) Includes positive and negative imbalances (difference between the electricity effectively fed-in and as scheduled).
CAPITAL EXPENDITURE
In 2018, capital expenditure amounted to €215 million, mainly
related to gas marketing initiatives (€161 million) and to the
maintenance, flexibility and upgrading initiatives of combined
cycle power plants (€46 million).
Capital Expenditure
Marketing
Marketing
Italy
Outside Italy
Power generation
International transport
Total of capital expenditure
of which:
Italy
Outside Italy
(€ million)
2018
207
161
93
68
46
8
215
139
76
2017
138
102
63
39
36
4
142
99
43
2016
110
69
32
37
41
10
120
73
47
Change
69
59
30
29
10
4
73
40
33
% Ch.
50.0
57.8
47.6
74.4
27.8
100.0
51.4
40.4
76.7
OPERATING REVIEW | GAS & POWER
REFINING & MARKETING
AND CHEMICALS
ADJUSTED OPERATING
PROFIT
€ million
REFINING BREAKEVEN
MARGIN AND SERM
$/barrel
Adjusted operating profit Refining & Marketing
Adjusted operating profit Chemicals
Refining Breakeven Margin
Standard Eni Refining Margin (SERM)
GHG EMISSIONS/
REFINING THROUGHPUTS
tons CO2eq/kt
55
4.2
2
.
4
~
6
1
0
2
5.0
8
3
.
7
1
0
2
3.7
0
3
.
8
1
0
2
2016
278
2017
258
2018
253
8
7
2
5
0
3
1
3
5
0
6
4
0
9
3
)
0
1
(
6
1
0
2
7
1
0
2
8
1
0
2
Performance of the year
● In 2018, the total recordable injury rate (TRIR) confirms Eni’s
● In 2018, Eni’s refining throughputs amounted to 23.23 mmtonnes,
commitment in the field of health and security with a decrease
by 9.7% compared to 2017, with both employees and contractors
contribution (down by 12.5% and 10.1%, respectively).
● Greenhouse gas emissions (GHG) reported an increase of 4.7%
in absolute terms following higher volumes processed.
● Energy efficiency projects contributed to a 2.1% decrease in
GHG emissions related to refining throughputs.
● In 2018, the Refining & Marketing and Chemicals segment
reported an adjusted operating profit of €380 million, down by
€611 million, or 62% from 2017.
The Refining & Marketing business reported an adjusted
operating profit of €390 million (down by 27%), consistent with
an unfavorable refining trading environment (SERM down by
26%). This result was also affected by increased standstills,
partly offset by the improved performance in marketing
activities driven by the effective commercial initiatives.
The Chemical business was negatively affected by rising costs of
oil-based feedstock in the first ten months of the year and by a
sharp decrease in polyethylene prices during the fourth quarter,
thus reporting an adjusted operating loss of €10 million from the
adjusted operating profit of €460 million reported in 2017.
● Breakeven refining margin at the budget scenario of exchange
rates and oil spreads was 3 $/barrel, in line with the guidance.
lower y-o-y (down by 3.3%) due to lower throughputs at the
Taranto plant, reflecting higher crude oil volumes processed on
behalf of third parties, at the Milazzo refinery due to maintenance
standstills and at the Bayernoil refinery following an event
occurred in September. These negatives were partially offset
by higher volumes processed at the Sannazzaro and Livorno
refineries, with the latter affected in 2017 by a shutdown due to a
force majeure event.
● Production of biofuels from vegetable oil at the Venice
green refinery amounted to 0.25 mmtonnes, up by 4.2%
compared 2017.
● Retail sales in Italy were 5.91 mmtonnes, slightly decreased
by 1.7% from 2017.
● Retail sales in the rest of Europe (2.48 mmtonnes) were down
by 2% compared to the previous year, mainly due to lower
volumes traded in Germany, due to the event occurred at
Bayernoil refinery and in France.
● Sales of petrochemical products in Europe amounted to 4.94
mmtonnes, recording an increase of 6.3% y-o-y, due to higher
intermediates sale volumes.
● Capital expenditure of €877 million mainly related to refining
activities.
GREEN REFINERY
THROUGHPUTS
AVERAGE
REFINERY
PLANT
UTILIZATION RATE
PRODUCTION OF
PETROCHEMICAL
PRODUCTS
AVERAGE
PETROCHEMICAL
PLANT
UTILIZATION RATE
+4 % vs. 2017
at 0.25 mmtonnes
91 %
90% in 2017
9,483 ktonnes
+6% vs. 2017
76 %
73% in 2017
56
Acquisition of new refining capacity in the Middle East
In January 2019, Eni signed a Share Purchase Agreement with
Abu Dhabi National Oil Company (ADNOC) for the acquisition of
a 20% interest in the ADNOC Refining company, one of the top
worldwide in terms of refining capacity (with an overall capacity
of more than 900 kbbl/d). Additionally, the agreement includes
the creation of a joint venture engaged in oil products trading
activities, participated by Eni with a 20% interest, ADNOC with a
65% interest and Österreichische Mineralölverwaltung (OMV) with
a 15% interest.
The total consideration of the deal amounts to $3.3 billion, net of
acquired debt and possible price adjustments at the closing date.
The transaction is subject to the approval by the relevant authorities.
The transaction is in line with Eni’s strategy finalized to geographical
diversification and value chain integration.
Eni, with its expertise, will provide support to the technological
development of the three refineries operated by ADNOC Refining,
located in Ruwais and Abu Dhabi areas. The agreement, one of
the most remarkable transaction finalized in the refining sector,
increased downstream capacity by 35% and is expected to halve the
breakeven refining margin to 1.5 $/barrel in the long term.
Agreements to support circular economy
As part of its commitment in circular economy, Eni launched a
number of partnerships with some Italian municipalities, Vatican
City and multi-utility companies operating in waste treatment
and local public transport (in Taranto, Turin, Venice, Rome and in
some municipalities of Emilia Romagna) for the exploitation of civil
waste and organic raw materials by using them as feedstock to
produce energy resources like biofuels. These partnerships aim to
Green chemicals development
promote the use of Eni Diesel + in local public transport, in order
to reduce GHG emissions, thanks to a 15% renewable component,
and to establish a network for collecting non-edible feedstock,
such as used cooking oil and other waste of biological origin, for the
subsequent transformation into biofuel at the Eni biorefineries in
Venice and in Gela, with the latter starting from 2019.
Eni continues to be focused on its commitment in the development
of green chemicals based on use of renewable resources through
the acquisition of activities in the segment of green chemicals of
the Mossi & Ghisolfi Group, finalized at the year-end. In particular,
the new assets will allow the valorization of biomass.
Development activities also include the re-launch of the
international licensing of a proprietary technology to produce
second generation bio-ethanol, to meet the growing demand and
sustainability criteria required for bio-fuels.
Partnerships
Signed a partnership between Versalis and Italian producers
to establish a supply chain aimed at recycling synthetic grass
from sports fields.
Versalis and SABIC, a company active in the reactors segment,
signed an agreement to develop an innovative technology
for natural gas conversion into synthesis gas to be
further transformed into high value fuels and chemicals (such
as methanol).
New elastomers unit
In September 2018, started up a new plant in Ferrara for the
production of high value products which will mainly supply the
automotive industry. The project, that consolidates the presence
of Eni in the territory, will increase overall production capacity, to
update elastomer products portfolio and to increase employment.
Chemical international development
As a part of Eni’s commitment in the chemical international
development, was signed an agreement with Mazrui Energy
Service, a leading service company in the Oil & Gas industry in the
Middle East, to establish a joint venture for the marketing
of innovative chemicals. The partnership with Mazrui will enable
to enhance the Versalis know-how and proprietary technologies
and to compete against major players in the market.
OPERATING REVIEW | REFINING & MARKETING AND CHEMICALS 57
REFINING & MARKETING
SUPPLY AND TRADING
In 2018, were purchased 22.62 mmtonnes of crude (24.28
mmtonnes in 2017), of which 4.14 mmtonnes by equity crude
oil, 10.01 mmtonnes on the spot market and 8.47 mmtonnes by
producer’s Countries with term contracts.
The breakdown by geographic area was as follows: 36% of
purchased crude came from the Middle East, 18% from Russia,
14% from Italy, 13% from Central Asia, 10% from North Africa, 3%
from West Africa, 2% from North Sea and 4% 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
(a) Include change in inventories, decrease due to transportation, consumption and losses.
REFINING
In 2018, Eni’s refining throughputs in Europe were 23.23 mmtonnes,
decreased by 3.3% from 2017 due to the lower throughputs at the
Taranto plant, reflecting higher crude oil volumes processed on behalf
of third parties maintenance standstills at the Milazzo refinery, and
at the Bayernoil refinery following an event occurred in September.
These negatives were partially offset by the better performance
at the Sannazzaro and Livorno refineries, with the latter affected
in 2017 by a shutdown due to a force majeure event. In Italy, the
decrease of refinery throughputs (down by 2.2%) was due to the
above mentioned drivers. The volumes of biofuels produced from
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
Green refinery 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 IN ITALY AND OUTSIDE ITALY
of which: refinery throughputs of equity crude on own account
TOTAL SALES OF REFINED PRODUCTS IN ITALY AND OUTSIDE ITALY
Crude oil sales
TOTAL SALES
(mmtonnes)
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
2016
3.43
19.92
23.35
1.35
11.20
35.90
(0.37)
(1.92)
33.61
Change
0.63
(2.29)
(1.66)
(0.31)
0.63
(1.34)
(0.01)
0.49
(0.86)
% Ch.
17.9
(11.0)
(6.8)
(32.3)
5.8
(3.7)
(2.9)
27.8
(2.5)
vegetable oil at the Venice green refinery increased by 4.2% from
2017. Outside Italy, Eni’s refining throughputs were 2.55 mmtonnes,
down by approximately 320 ktonnes or 11.1% due to the downtime
of the Bayernoil refinery in September. Total throughputs in wholly-
owned refineries were 16.78 mmtonnes, up by 0.75 mmtonnes or
4.7% compared to 2017.
The refinery utilization rate, ratio between throughputs and refinery
capacity, is 91%.
Approximately 18.3% of processed crude was supplied by Eni’s
Exploration & Production segment, increased from 2017 (15.2%).
(mmtonnes)
2018
2017
2016
Change
% Ch.
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
17.37
(0.27)
4.51
21.61
(1.53)
20.08
6.28
(0.39)
(0.37)
25.60
0.21
2.91
(0.22)
2.69
4.72
0.40
7.81
24.52
3.43
33.41
0.20
33.61
0.75
(0.69)
(0.53)
(0.47)
(0.02)
(0.49)
0.76
(0.08)
(0.01)
0.18
0.01
(0.32)
0.02
(0.30)
(0.24)
0.08
(0.46)
(0.79)
0.63
(0.28)
(0.58)
(0.86)
4.7
..
(9.7)
(2.2)
(1.5)
(2.5)
11.3
(17.4)
(2.9)
0.7
4.2
(11.1)
9.1
(11.3)
(5.5)
17.4
(6.2)
(3.3)
17.9
(0.8)
(67.4)
(2.5)
OPERATING REVIEW | REFINING & MARKETING AND CHEMICALS Eni Annual Report 2018
58
MARKETING OF REFINED PRODUCTS
In 2018, retail sales of refined products (32.92 mmtonnes)
were down by 0.28 mmtonnes or by approximately 1% from
2017, mainly due to the decrease of retail and wholesale
sales 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
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
2016
5.93
8.16
1.02
10.49
25.60
2.66
3.18
0.43
1.54
7.81
33.41
Change
(0.10)
(0.10)
0.10
0.28
0.18
(0.05)
(0.21)
0.02
(0.22)
(0.46)
(0.28)
% Ch.
(1.7)
(1.3)
11.6
2.5
0.7
(2.0)
(6.9)
4.4
(15.1)
(6.2)
(0.8)
Retail sales in Italy
In 2018, retail sales in Italy were 5.91 mmtonnes, with a slight
decrease compared to 2017 (about 100 ktonnes from 2017 or
1.7%). Average gasoline and gasoil throughput (1,589 kliters) was
almost unchanged from 2017. Eni’s retail market share of 2018
was 24%, slightly decreased from 2017 (24.3%). As of December
31, 2018, Eni’s retail network in Italy consisted of 4,223 service
stations, lower by 87 units from December 31, 2017 (4,310
service stations), resulting from the negative balance of
acquisitions/releases of lease concessions
(74 units), closure of low throughput stations (10 units)
and the reduction in motorway concessions netted by
the new opening (3 units).
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 WHOLESALE SALES
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
2016
14.09
5.93
1.53
3.99
0.36
0.04
8.16
3.70
0.14
0.22
0.49
0.08
1.01
1.82
0.70
6.27
1.27
3.44
0.62
0.13
0.10
0.49
0.22
20.36
Change
(0.20)
(0.10)
(0.05)
(0.05)
(0.10)
(0.11)
(0.01)
(0.01)
(0.05)
0.02
0.06
(0.24)
0.09
(0.13)
(0.17)
0.01
(0.01)
(0.01)
(0.02)
(0.44)
% Ch.
(1.5)
(1.7)
(3.3)
(1.2)
(1.3)
(3.3)
(12.5)
(4.8)
(5.9)
1.0
9.1
(4.0)
7.4
(4.0)
(34.0)
7.7
(10.0)
(2.0)
(7.4)
(2.2)
OPERATING REVIEW | REFINING & MARKETING AND CHEMICALS
59
CONSUMPTION AND MARKET SHARE IN ITALY
Retail market share (%)
Domestic consumption
Average throughput (kliters)
24.3
24.3
24.0
1
5
5
,
1
6
1
0
2
8
8
5
,
1
7
1
0
2
9
8
5
,
1
8
1
0
2
Retail sales in the rest of Europe
Retail sales in the rest of Europe were 2.48 mmtonnes, reducing
from 2017 (down by 2%) due to lower volumes traded in Germany
due to the event occurred at Bayernoil refinery and France.
At December 31, 2018, Eni’s retail network in the rest
of Europe consisted of 1,225 units, decreasing by 9 units
from December 31, 2017, mainly in Germany. Average
throughput (2,391 kliters) decreased by 49 kliters compared
to 2017 (2,440 kliters).
Wholesale and other sales
Wholesale sales in Italy amounted to 7.54 mmtonnes,
unchanged from 2017, mainly due to lower volumes marketed
of gasoil offset by higher sales of other products.
Wholesale sales in the rest of Europe were 2.82 mmtonnes,
down by 6.9% from 2017 due to lower volumes sold in Germany
and France, partly offset by higher volumes in Spain. Supplies
of feedstock to the petrochemical industry (0.96 mmtonnes)
increased by 11.6%. Other sales in Italy and outside Italy
(12.74 mmtonnes) slightly increased by 0.06 mmtonnes,
due to higher 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)
2018
7,130
2,353
9,483
2017
6,595
2,360
8,955
2016
Change
6,580
2,229
8,809
535
(7)
528
% Ch.
8.1
(0.3)
5.9
(5,085)
(4,566)
(4,917)
(519)
(11.4)
540
4,938
3,087
1,851
4,938
257
4,646
2,748
1,898
4,646
853
4,745
2,956
1,789
4,745
283
292
339
(47)
292
110.1
6.3
12.3
(2.5)
6.3
Petrochemical sales of 4,938 ktonnes increased from 2017 (up
by 292 ktonnes, or 6.3%). The main increases were registered in
olefins (up by 14.8%) and derivatives (up by 20.4%), partly offset
by lower sales volumes of polyethylene (down by 6.3%) and
elastomers (down by 3.2%).
Average unit sales prices of the intermediates business
increased by 7.1% from 2017, with olefins and aromatics up by
10.9% and 4.2%, respectively. The polymers reported a decrease
of 2.4% from 2017.
Petrochemical production of 9,483 ktonnes increased by
528 ktonnes (up by 5.9%) mainly due to higher production of
intermediates business (up by 8.1%), in particular derivatives up by
17.6%; the polymers productions were substantially in line despite
the improvement of styrenics (up by 8.3%).
The main increases in production were registered at the Porto
Marghera site (up by 22.9%), due to a recovery of production
capacity for a shutdown in 2017, as well as Szàzhalombatta,
Mantova and Priolo sites. Decreasing production at the Ferrara,
Brindisi and Oberhausen sites due to unplanned shutdowns of the
plants in 2018. Nominal capacity of plants is in line with 2017.
The average plant utilization rate calculated on nominal capacity
was 76.2%, increasing from 2017 (72.8%).
BUSINESS TRENDS
Intermediates
Intermediates revenues (€2,401 million) increased by €413
million from 2017 (up by 20.8%) reflecting the higher commodity
prices scenario that influences average intermediates prices of
the main product of the business unit. Sales increased by 12.3%,
in particular ethylene (up by 30.3%) and derivatives
(up by 20.4%) driven by higher availability of product following
the shutdowns in 2017. Average unit prices increased by
7.1%, in particular olefins (up by 10.9%) and aromatics (up by
4.1%); decreasing of derivatives (down by 9.3%). Intermediates
production (7,130 ktonnes) registered an increase of 8.1% from
the last year. Increasing production of derivatives (up by 17.6%),
aromatics (up by 8.3%) and olefins (up by 7%).
OPERATING REVIEW | REFINING & MARKETING AND CHEMICALS Eni Annual Report 2018
60
Polymers
Polymers revenues (€2,589 million) decreased by €141 million
or 5.2% from 2017 due to lower volumes sold (down by 2.5%),
as well as to the decrease of the average unit prices (down
by 2.4%). The styrenics business benefitted from higher sold
volumes (up by 5.8%) reflecting higher product availability;
slightly decrease in prices of sold volumes(down by 1.4%).
Polyethylene volumes decreased (down by 6.4%) due to
oversupply and competitive pressure from cheaper products
streams from the Middle-East and the USA; decreasing of average
prices (down by 3.9%).
In the elastomers business, a decrease of sold volumes was
attributable to SBR rubbers (down by 3.6%), special rubbers
EPDM (down by 5.7%) and lattices (down by 16.9%); increasing of
thermoplastic rubbers (up by 2.5%) and BR (up by 1.2%).
Higher styrenics volumes sold (up by 5.8%) was mainly driven by
higher sales of styrene (up by 21.1%), compact polystyrene (up
by 8.2%) and expandable polystyrene (up by 5.3%); lower sales of
ABS/SAN (down by 16%).
Overall, the sold volumes of polyethylene business reported a
decrease (down by 6.4%) with lower sales of EVA, LDPE and LLDPE
(down by 16.1%, 8.6% and 5.1%, respectively), while volumes of
HDPE increased (up by 2.2%).
Polymers productions are in line with 2017 (2,353 ktonnes)
despite the lower productions of polyethylene (down by
7.3%) and elastomers (down by 2.7%). The styrenics business
reported higher production of styrene (up by 12.1%) and HIPS
(up by 11.7%).
CAPITAL EXPENDITURE
In 2018, capital expenditure in the Refining & Marketing and
Chemicals segment amounted to €877 million and mainly
regarded: (i) refining activity in Italy and outside Italy (€587
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,
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 (€139
million); (iii) in the Chemical business, upgrading activities
(€52 million), maintenance (€32 million), environmental
protection, safety and environmental regulation (€26 million),
as well as upkeeping of plants (€21 million).
Research and Development (R&D) expenditure in the
Refining & Marketing and Chemicals segment amounted
to approximately €44 million. During the year, 20 patent
applications were filed.
Capital expenditure
Refining
Marketing
Chemicals
TOTAL
(€ million)
2018
2017
2016
Change
587
139
726
151
877
395
131
526
203
729
298
123
421
243
664
192
8
200
(52)
148
% Ch.
48.6
6.1
38.0
(25.6)
20.3
OPERATING REVIEW | REFINING & MARKETING AND CHEMICALS
CORPORATE
AND OTHER ACTIVITIES
61
TREATED GROUNDWATER
REUSED/REINJECTED
mmcm
2016
2018
2017
4.2
12.2 mmcm
2016–2018
4.8
3.2
TECHNOLOGY
INNOVATION
First patent filing applications
(number)
R&D expenditure (€ million)
11
1
4
6
1
0
2
7
4
4
7
1
0
2
13
7
5
8
1
0
2
NET SALES FROM
OPERATIONS
€ million
2016
2017
2018
1,343
1,462
1,589
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 Uninersity, 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 Syndial which runs reclamation and decommissioning activities pertaining to certain businesses which Eni exited, divested or shut
down in past years, as well as Energy Solutions business which engages in developing the business of renewable energy.
Performance of the year
● In 2018, the treated groundwater (TAF) and reused in
production increased by 12%. 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.
logistical services, as well as remediation initiatives carried out
for Eni’s Group.
● The capital expenditure reported in 2018 (€143 million) were
mainly focused on the development of renewable projects,
circular economy and digitalization.
● In 2018,the photovoltaic installed capacity amounted to 39.8 MW.
● In 2018, research and development expenditure amounted to €57
million (€44 million in 2017). 13 patent applications were filed.
● In 2018, the Corporate and Other activities segment reported
an increase of revenues of approximately 9% mainly as result
of the growth of global client activities, the environmental
● In 2018, the share of recovered/recycled waste increased
compared to 2017, reaching approximately 40% of total waste
disposed of.
GROUNDWATER USED IN
PRODUCTION/REINJECTED
VS. TOTAL TREATED
GROUNDWATER
PHOTOVOLTAIC
INSTALLED
CAPACITY
R&D
EXPENDITURE
21 % in 2018
39.8 MW in 2018
+30 %
vs. 2017
RECOVERED
WASTE
VS. RECOVERABLE
WASTE
58 % in 2018
+10% vs. 2017
62
Main activities of the year
Italy Eni’s commitment to renewables projects is going on, through
the implementation of the Project Italy. In particular were launched
the following photovoltaic plants: (i) in March 2018, the 1MW plant
of the Green Data Center in Ferrera Erbognone; (ii) in July 2018,
the 1MW plant of Gela in the area called “Isola 10”; and (iii) in
September 2018, the 26 MW plant of Assemini. The administrative
procedure was launched for the realization of two photovoltaic
plants in the production area of Porto Marghera in a context of
territorial requalification.
In February 2019, was launched the construction of a 31 MW
photovoltaic plant in the industrial area of Porto Torres. The project
has been authorized by the Relevant Authority with the “Unique
Authorization” allowing the construction and operation of the
project. The annual production will be addressed, for a 50% share, to
the internal consumption of the company located in the industrial
site and will allow to avoid the emission of approximately 22,000
tons of CO2eq per year. In December 2018, was launched at Gela
refinery the pilot plant Waste to Fuel, a proprietary technology
created by Eni which transforms the Organic Fraction of Municipal
Solid Waste (OFMSW) into bio-oil, which can be used as bunker fuel
or for bio-diesel production. The first production was obtained in
January 2019. The success of the pilot project will be a functional
reference for the development of further future industrial-scale
initiatives. The development of Ponticelle NOI (New Innovation
Opportunities) is ongoing at the industrial site of Ravenna,
with an overall investment of €60 million.
The program includes the permanent safety activities and the
innovative, sustainable and productive requalification of the area,
according to the pillars of circular economy. The area involved
covers approximately 26 hectares where it is foreseen: (i) the
realization of a multipurpose environmental platform addressed
to the processing of materials coming from the site and other
Eni’s activities with the goal of maximize their recovery; (ii) a
technology centre for reclamations, to test innovative remediation
technologies; (iii) a photovoltaic system to provide energy to
support productive activities; and (iv) a Waste to Fuel plant.
In March 2019, a Memorandum of Understanding was signed
with Veritas, a multi-utility company operating in collection,
enhancement and treatment of waste in the Venetian territory.
The agreement foresees the realization, in a decommissioned
and reclaimed area of Porto Marghera, of a plant that will apply
the Waste to Fuel technology to convert organic solid waste into
bio-oil or bio-methane.
Australia In February 2019, was completed the acquisition of a
project for the construction of the 33.7 MW photovoltaic power plant
in the site of Katherine, located in the north of the Country. The
plant will enter into production at the end of 2019, be equipped with
an energy accumulation system and allow to avoid the emission of
about 63,000 tonnes of CO2eq per year.
Algeria In November 2018, was completed the construction of the
10 MW photovoltaic plant located at the Bir production site Rebaa
North (BRN) in Block 403 (Eni’s interest 50%). The plant will provide
electricity to the productive facilities of the field and, at the same
time, contribute to reduce greenhouse gas emissions, as part of a
decarbonization process for the Country’s energy system.
Additionally, in order to strengthen the partnership in renewable
energy business, Eni signed the following agreements with
Sonatrach: (i) for the implementation of a research laboratory
at the BRN production site to test solar technologies in a desert
environment; (ii) for the creation of a joint venture that will
implement and manage solar power plants at the production sites
operated by Sonatrach in the Country.
Kazakhstan In December 2018, started the building, in partnership
with General Electric (GE) of the first Eni’s wind farm energy with
a total capacity of 50 MW, located at Badamsha site. The project,
which is part of the agreement between Eni, GE and the Minister of
Energy of the Republic of Kazakhstan, will enter into operation at
the end of 2019.
Pakistan In 2018, preliminary activities were launched to build the 10
MW solar system to support the production facilities at the Bhit field
(Eni operator with a 40% interest). The start-up is expected in 2019.
Tunisia In 2018, two photovoltaic projects were sanctioned: (i) the 5
MW plant for energy supply to the production facilities at the Adam
field (Eni operator with a 50% interest); (ii) the 10 MW Tataouine
plant (Eni operator with a 50% interest) which provides for the
supply of the energy produced to the national company STEG on the
basis of a 20-year Power Purchase Agreement.
11_Corporate_ING.indd 62
10/05/19 09:23
OPERATING REVIEW | CORPORATE AND OTHER ACTIVITIES 63
FINANCIAL
REVIEW
PROFIT AND LOSS ACCOUNT
Net sales from operations
Other income and revenues
Operating expenses
Other operating income (expense)
Depreciation, depletion, amortization
Impairment reversals (impairment losses), 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) - continuing operations
Net profit (loss) - discontinued operations
Net profit (loss)
attributable to:
Eni’s shareholders
- continuing operations
- discontinued operations
Non-controlling interest
- continuing operations
- discontinued operations
(€ million)
2018
75,822
1,116
(59,130)
129
(6,988)
(866)
(100)
9,983
(971)
1,095
10,107
(5,970)
59.1
4,137
2017
66,919
4,058
(55,412)
(32)
(7,483)
225
(263)
8,012
(1,236)
68
6,844
(3,467)
50.7
3,377
4,137
3,377
4,126
4,126
3,374
3,374
11
11
3
3
2016
55,762
931
(47,118)
16
(7,559)
475
(350)
2,157
(885)
(380)
892
(1,936)
217.0
(1,044)
(413)
(1,457)
(1,464)
(1,051)
(413)
7
7
Change
8,903
(2,942)
(3,718)
161
495
(1,091)
163
1,971
265
1,027
3,263
(2,503)
8.4
760
% Ch.
13.3
(72.5)
(6.7)
..
6.6
..
62.0
24.6
21.4
..
47.7
(72.2)
22.5
760
22.5
752
752
8
8
22.3
22.3
..
..
..
In the full year of 2018, Eni reported an operating profit of €9,983
million and a net profit attributable to Eni’s shareholders of
€4,126 million, increased approximately by 25% and 22% from
2017, respectively. Eni’s results benefitted from a better trading
environment and an improved performance.
In 2018, Brent prices increased by 31% on average from 2017 to
71 $/barrel, in a highly volatile scenario. In the first ten months
of the year, oil prices built on gains peaking at 85 $/barrel in
October, the highest level in the last four years, due to a global
economic recovery and a balanced demand/supply backdrop.
Starting from November, alongside a sharp correction in the
global financial markets, oil prices entered a downturn losing
about 40% from its peak, falling to approximately 50 $/barrel
at the end of the year, due to signs of weakening global growth,
oversupply, uncertainty tied to the commercial dispute between
USA and China, the Brexit, as well as geopolitical factors. In
December, OPEC and Russia announced a production cut of 1.2
million barrel/day effective from 2019. In this scenario, Eni’s E&P
segment reported an increase in operating profit of €2.6 billion,
leveraging on better prices and production increases, with the
latter boosted by a shift in the production mix towards barrels
with higher profitability.
The G&P segment improved its operating profit by approximately
€0.6 billion, driven by the overall restructuring of all the business
lines, effective management of flexibilities associated with the
portfolio of long-term gas contracts, optimization in the power
business and in logistics, as well as growth in the LNG business
leveraging its integration with the E&P segment. The downstream oil
and chemical businesses (approximately down by €1.4 billion) were
negatively affected by a squeeze in margins (the SERM benchmark
refining margin was down by 26% to 3.7 $/barrel; the cracker margin
down by 11% and the polyethylene margin was down by 69%)
because of rapidly-escalating oil-based feedstock costs which were
not fully recovered in the final prices of products due to shrinking
demand for commodities and competitive pressure from more
efficient producers.
Declining oil and product prices at year end resulted in
a loss on inventory evaluation compared to a gain in
the previous year (approximately down €225 million).
Extraordinary/non-recurring items reported a loss of €388
million (compared to non-recurring gains of €839 million in the
full year of 2017) reflecting the substantial netting between
the gain of the business combination of Eni Norge and Point
Resources to create Vår Energi (as difference between the fair
value of the investment and the book value of disposed net
asset) and the effect of suspending the amortization of assets
since the beginning of the second half of the year, following the
classification as asset held for sale, which offset impairment
losses and risk provisions.
64
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)
2018
71.04
1.181
60.15
3.7
260
243
2017
54.27
1.130
48.03
5.0
211
183
2016
43.69
1.107
39.47
4.2
168
148
% Ch.
30.9
4.5
25.2
(26.0)
23.2
32.8
(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
refineries’ product yields.
(d) €/kcm.
Cash flow from operating activities amounted to €13,647 million
for the full year of 2018 and was up by 35% from the full year of 2017
driven by an improved underlying performance and scenario effects.
Adjusted net cash flow from operating activities before changes
in working capital at replacement cost was €12,662 million,
up by 37% from 2017. This adjusted measure is derived by
excluding certain non-recurring charges: an expense recognized
in connection with the final outcome of an arbitration proceeding
(€313 million), an extraordinary allowance for doubtful accounts
in the E&P segment (€158 million) and an expense related to the
sale of a 10% interest in the Zohr project due to the fact that they
related to the asset disposals.
At a Brent price of 71 $/barrel in 2018, adjusted cash flow from
operations amounted to approximately €13.45 billion and positive
changes in receivables and payables associated with investing
activities (mainly including the cash-in of the deferred price of the
Zohr disposals made in 2017) amounted to €0.9 billion. Those inflows
funded capex of €7.94 billion and the dividend of €2.95 billion, leaving
a surplus of around €3.5 billion. Consequently, on the basis of the
Group’s cash flow sensitivity to the Brent scenario which assumes
a change of approximately €0.19 billion in cash flow for each one-US
dollar change in the Brent price (and vice versa), the cash neutrality
for funding full year capex and the floor dividend would have been
achieved at 52 $/barrel. This is re-determined in 55 $/barrel when
excluding from cash inflows the deferred tranches of the consideration
on the disposal of Eni’s interests in Zohr made in 2017 (€450 million),
being these the unique non-organic components of the cash flow.
Net borrowings at December 31, 2018 was €8,289 million, down
by €2,627 million as of December 31, 2017. Gearing was 0.14,
the lower end of the European peer group and leverage reduced
to 0.16, down from 0.23 as of December 31, 2017.
Adjusted results and breakdown of special items
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)
2018
9,983
96
1,161
11,240
4,126
69
388
4,583
56.2
2017
8,012
(219)
(1,990)
5,803
2016
2,157
(175)
333
2,315
3,374
(156)
(839)
2,379
56.8
(1,051)
(120)
831
(340)
120.6
Change
1,971
% Ch.
24.6
5,437
93.7
752
22.3
2,204
92.6
Net profit includes special items consist of net charges of €388
million, relating to the following:
(i)
net impairment losses of certain E&P assets resulting an
overall effect of €726 million driven by a lower-than-expected
performance at certain fields as well as in order to align them
with the fair-value of selling price;
(ii) an impairment reversal at certain transportation activities
outside Italy due to the reduction of the country risk premium
factored in the discount rate (€66 million);
(iii) the reinstatement of correlation amounting €375 million
between hydrocarbon production and reserve depletion
by accruing the underlying UOP-based amortization charges
of Eni Norge subsidiary classified as held for sale in accordance
to IFRS 5 due to the pending business combination with
Point Resources;
impairment losses (€193 million) mainly regarding the
(iv)
write-down of capital expenditure relating to certain Cash
Generating Units in the R&M business, which were impaired
in previous reporting periods and continued to lack any
profitability prospects;
(v) a charge taken in connection with the outcome of an arbitration
proceeding relating a long-term contract to purchase
regasification services, which resulted in the termination of the
contract and of the related annual fees charged to Eni. It also
awarded the counterparty equitable compensation of €289
million (plus financial interests of €24 million);
(vi) valuation allowance for doubtful accounts in connection with
cost recovery in E&P segment to align the recoverable amount
(€158 million);
(vii) a gain recorded on the disposal of a 10% interest in the Shorouk
and Nour concessions, offshore Egypt (€339 million net
of assignment bonus and other charges);
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEW
65
(viii) provision for redundancy incentives (€155 million);
(ix) environmental provisions (€325 million) mainly relating to R&M
(x)
and Chemicals and E&P segments;
the effects of fair-valued commodity derivatives that lacked the
formal criteria to be accounted as hedges under IFRS (net gains
of €133 million);
(xi) exchange rate differences and derivatives reclassified to
operating profit (net gain of €107 million) mainly refferred to
G&P segment, 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;
(xii) the gain on the business combination involving Eni Norge
and Point Resources, fully-owned by Eni and HitecVision
respectively, which led to the creation of the equity-accounted
joint venture Vår Energi, jointly controlled by Eni (69.6%) and
HitecVision, with a gain of approximately €890 million as
difference between the fair value of Eni’s interest in the venture
and the book value of disposed net assets;
(xiii) an impairment reversal (€262 million) at the Angola LNG
equity-accounted entity due to improved project economics;
(xiv) the impairment of an equity accounted upstream investment
(approximately €200 million) due to the de-booking of
undeveloped reserves at a certain project driven by a
deteriorating operational local environment;
(xv) Eni’s interest of extraordinary charges/impairment losses
recognized by the Saipem joint venture (€154 million);
(xvi) 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 (€99 million).
Breakdown of special items
Special items of operating profit (loss)
- environmental charges
- impairment losses (impairments reversal), net
- impairment of exploration projects
- 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
- net impairment of deferred tax assets of upstream business outside Italy
- USA tax reform
- taxes on special items of operating profit and other special items
Total special items of net profit (loss)
(€ million)
2018
1,161
325
866
(452)
380
155
(133)
107
(375)
288
(85)
(107)
(798)
(909)
67
110
99
11
388
2017
(1,990)
208
(221)
(3,283)
448
49
146
(248)
911
502
248
372
(163)
537
277
115
162
(839)
2016
333
193
(459)
7
(10)
151
47
(427)
(19)
850
166
19
817
(57)
896
(72)
170
6
(248)
1,244
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:
- Non-controlling interest
- Eni’s shareholders
(€ million)
2018
4,955
310
238
(965)
56
4,594
11
4,583
2017
2,724
52
663
(1,041)
(16)
2,382
3
2,379
2016
508
(330)
419
(991)
61
(333)
7
(340)
Change
2,231
258
(425)
76
72
2,212
8
2,204
% Ch.
81.9
..
(64.1)
7.3
92.9
..
92.6
(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.
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEWEni Annual Report 2018
66
Profit and loss analysis
Net sales from operations
Exploration & Production
Gas & Power
Refining & Marketing and Chemicals
- Refining & Marketing
- Chemicals
- Consolidation adjustments
Corporate and other activities
Consolidation adjustments
Net sales from operations
Other income and revenues
Total revenues
(€ million)
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
2016
16,089
40,961
18,733
14,932
4,196
(395)
1,343
(21,364)
55,762
931
56,693
Change
6,219
5,067
3,109
2,958
272
127
(5,619)
8,903
(2,942)
5,961
% Ch.
31.9
10.0
14.1
16.7
5.6
8.7
13.3
(72.5)
8.4
Net sales from operations in the full year of 2018 (€75,822
million) increased by €8,903 million or 13.3% from 2017, driven
by the recovery of commodity prices.
Revenues generated by the Exploration & Production segment
(€25,744 million) increased by €6,219 million or up by
31.9%. This was due to higher average realizations on equity
hydrocarbons (oil realizations up by 30.8%; gas realizations up
by 41% on average in dollar terms) driven by increasing prices
for the marker Brent and better gas prices due to the ramp-up of
production with higher-than-average gas realizations.
Revenues generated by the Gas & Power segment (€55,690
million) increased by €5,067 million or up by 10%.
The increase reflected higher natural gas and power prices, as well
as increased revenues from trading activity due to higher oil and
products selling prices.
Revenues generated by the Refining & Marketing and Chemicals
segment (€25,216 million) increased by €3,109 million (or up by
14.1%) mainly in the Refining & Marketing business with an increase
of €2,958 million due to higher commodity prices. The average
selling prices of gasoline and gasoil reported an increase of 14% and
30%, respectively. Revenues generated in the Chemical business
slightly increased (up by €272 million) boosted by the increase in
average selling prices as well as by higher volumes sold (up by 6%).
Eni’s other income and revenues recorded gains on the disposal of
non-strategic assets and other revenues.
The positive balance of €1,116 million mainly related to the gain on the
divestment of a 10% interest in the Zohr project. The reduction from the
full year 2017 is due to the gains on disposals recorded in 2017 on the
sale of a 40% interest in the Zohr gas field in Egypt (€1,281 million)
and of a 25% interest in Area 4 offshore Mozambique (€1,985 million)
where development activity is underway.
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)
2018
55,622
415
3,093
155
59,130
2017
51,548
913
2,951
49
55,412
2016
43,278
846
2,994
47
47,118
Change
4,074
(498)
142
% Ch.
7.9
(54.5)
4.8
3,718
6.7
Operating expenses for 2018 (€59,130 million) increased by
€3,718 million from 2017, up by 6.7%. Purchases, services and
other (€55,622 million) increased by €4,074 million or 7.9%
primarily reflecting higher supply cost of raw materials (natural gas
under long-term supply contracts, refinery and chemical feedstock
and hydrocarbons purchased for resale).
Payroll and related costs (€3,093 million) increased by €142
million from 2017, up by 4.8%, mainly due to the increase in average
wages and higher provisions for redundancy incentives.
These increases were partly offset by a reduction in the average
number of employees outside Italy and the appreciation of the euro
against the US dollar. Payroll and related costs include special item
of €155 million mainly referring to an early retirement program in
the Eni gas e luce SpA subsidiary in accordance with Art. 4 of Italian
Law No. 92/2012.
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEW 67
DD&A, impairments, reversals 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), net
Depreciation, depletion, amortization, impairments and reversals, net
Write-off of tangible and intangible assets
(€ million)
2018
6,152
408
399
59
(30)
6,988
866
7,854
100
7,954
2017
6,747
345
360
60
(29)
7,483
(225)
7,258
263
7,521
2016
6,772
354
389
72
(28)
7,559
(475)
7,084
350
7,434
Change
(595)
63
39
(1)
(1)
(495)
1,091
596
(163)
433
% Ch.
(8.8)
18.3
10.8
(1.7)
(6.6)
..
8.2
(62.0)
5.8
Depreciation, depletion and amortization (€6,988 million)
decreased by approximately 7% from 2017, mainly in the Exploration
& Production segment due to the interruption of the UOP-based
amortization charges of Eni Norge subsidiary (€375 million),
classified as held for sale in accordance to IFRS 5 from the second
half of the year as a result of the pending business combination with
Point Resources, as well as the appreciation of the euro against the
US dollar, partly offset by new project start-ups and ramp-ups.
The breakdown of impairment charges (€866 million) is shown in the table below:
Impairment losses
Impairment reversals
Impairment losses (impairment reversals), net
Impairment losses on receivables related to non-recurring activities
Total
Exploration & Production
Gas & Power
Refining & Marketing and Chemicals
Corporate and other activities
Impairment losses (impairment reversals), net
(€ million)
(€ million)
2018
1,292
(426)
866
866
2018
726
(71)
193
18
866
2017
862
(1,087)
(225)
4
(221)
2016
1,067
(1,542)
(475)
16
(459)
2017
(158)
(146)
54
25
(225)
2016
(700)
81
104
40
(475)
Change
430
661
1,091
(4)
1,087
Change
884
75
139
(7)
1,091
Further information on impairment charges are described in the
paragraph “special items”.
Write-off of tangible and intangible assets (€100 million) mainly
related to the costs of exploratory wells lacking the requisites
for continuing capitalization because they did not encounter
commercial quantities of hydrocarbons in particular in Vietnam
and Morocco.
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)
2018
10,214
629
(380)
(691)
211
9,983
2017
7,651
75
981
(668)
(27)
8,012
2016
2,567
(391)
723
(681)
(61)
2,157
Change
2,563
554
(1,361)
(23)
238
1,971
% Ch.
33.5
..
..
(3.4)
24.6
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEWEni Annual Report 2018
68
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)
2018
9,983
96
1,161
11,240
10,850
543
380
(606)
73
11,240
2017
8,012
(219)
(1,990)
5,803
5,173
214
991
(542)
(33)
5,803
2016
2,157
(175)
333
2,315
2,494
(390)
583
(452)
80
2,315
Change
1,971
% Ch.
24.6
5,437
93.7
5,677
329
(611)
(64)
106
5,437
109.7
153.7
(61.7)
(11.8)
93.7
The increase in adjusted operating profit of €5.4 billion was due
to a favourable hydrocarbon prices scenario (€4 billion) and
the growth in the underlying performance (€1.4 billion) driven
by the production growth and the improved performance of
upstream projects with higher profit per boe.
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
- Net interest due to banks
- Net income from financial activities held for trading
- Net income from receivables and securities for non-financing operating activities
Income (expense) on derivative financial instruments
- Derivatives on exchange rate
- Derivatives on interest rate
- Derivates on securities
Exchange differences, net
Other finance income (expense)
- Net 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)
2018
(627)
(685)
18
32
8
(307)
(329)
22
341
(430)
132
(249)
(313)
(1,023)
52
(971)
2017
(834)
(751)
12
(111)
16
837
809
28
(905)
(407)
128
(264)
(271)
(1,309)
73
(1,236)
2016
(726)
(757)
15
(21)
37
(482)
(494)
(12)
24
676
(459)
143
(312)
(290)
(991)
106
(885)
Change
207
66
6
143
(8)
(1,144)
(1,138)
(6)
1,246
(23)
4
15
(42)
286
(21)
265
Net finance expense of €971 million decreased by €265 million
from 2017 mainly due to lower finance expenses related to debt
which reflected the €2,627 million decrease in net borrowings.
This improvement was due to the surplus generated by cash flow
from operations after funding capex and dividend.
Other finance income (expense) included finance charges
due to 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). These negatives
were partly offset y-o-y by the write-off of 2017 financial
receivables due by an equity accounted entities.
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEW
69
Net income from investments
The breakdown of the net income from investment of 2018 is provided in the table below:
2018
Share of gains (losses) from equity-accounted investments
Dividends
Net gains (losses) on disposals
Other income (expense), net
(€ million)
Exploration
& Production
158
193
19
885
1,255
Gas
& Power
9
(6)
25
28
Refining
& Marketing
and Chemicals
(67)
38
9
Corporate
and other
activities
(168)
(20)
(168)
Group
(68)
231
22
910
1,095
Net income from investments amounted to €1,095 million related to:
(i) dividends of €231 million paid by minor investments in certain
entities which were designated at fair value and mainly
related to Nigeria LNG Ltd (€187 million) and Saudi European
Petrochemical Co. (€35 million);
(ii) other net gains (€910 million) including the net gain on
the Vår Energi business combination (approximately €890
million);
(iii) the impairment reversal (€262 million) at the Angola LNG equity-
accounted entity due to improved project economics partly
offset by impairment loss of a joint venture due to deteriorated
operating environment (approximately €200 million).
These gains were partly offset by Eni’s share of losses recorded
by the Saipem joint venture (Eni’s interest 31%) due mainly to
the incurrence of impairment losses and certain extraordinary
charges by the investee.
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
(€ million)
2018
(68)
231
22
910
1,095
2017
(267)
205
163
(33)
68
2016
(326)
143
(14)
(183)
(380)
Change
199
26
(141)
943
1,027
Income taxes
Income taxes increased by €2,503 million to €5,970 million
mainly due to the increase of profit before income taxes (up
by €3,263 million from 2017). The reported tax rate was 59%
compared to 51% reported in 2017, reflecting lower gains free
of taxes or subject to a lower tax rate compared to the Group
average tax rate. Adjusted tax rate was 56.2%, slightly lower
from 2017, despite a higher tax rate in the E&P segment
(approximately 3 percentage point) due to the recognition of
lower deferred tax asset relating to certain projects.
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEWEni Annual Report 2018 70
Results by business segments1
Exploration & Production
Operating profit (loss)
Exclusion of special items:
- environmental charges
- impairment losses (impairment reversals), net
- impairment of exploration projects
- net gains on disposal of assets
- provision for redundancy incentives
- risk provisions
- commodity derivatives
- 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)
2018
10,214
636
110
726
2017
7,651
(2,478)
46
(154)
(442)
26
360
(3,269)
19
366
(6)
(138)
10,850
(366)
285
(5,814)
54.0
4,955
380
287
93
($/barrel)
($/kcf)
($/boe)
65.47
5.20
47.48
(68)
582
5,173
(50)
408
(2,807)
50.8
2,724
525
273
252
50.06
3.69
35.06
2016
2,567
(73)
(684)
7
(2)
24
105
19
(3)
461
2,494
(55)
68
(1,999)
79.7
508
374
204
170
39.18
3.27
29.14
Change
2,563
% Ch.
33.5
5,677
(316)
(123)
(3,007)
3.2
2,231
(145)
14
(159)
15.41
1.51
12.42
109.7
81.9
(27.6)
5.1
(63.1)
30.8
41.0
35.4
(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 2018, the Exploration & Production segment reported an
adjusted operating profit of €10,850 million more than doubled
y-o-y and the best result of the last four years. The better
performance was driven by higher realized prices on equity
hydrocarbons driven by the strong trend in crude oil prices in
the first ten months (which drove a 31% rise in price of the Brent
market benchmark, in dollar term) as well as production growth.
These positives were partly offset by the euro appreciation
over the US dollar (up by 4.5%). When excluding scenario
effect, the underlying performance reported a significant
increase, leveraging on a favorable volume/mix effects,
boosted by the increased contribution of barrels with higher
unitary profitability.
Adjusted operating profit excluded special items of €636 million.
Adjusted net profit was €4,955 million, an 82% increase y-o-y
due to improved operating performance, partially offset by the
write-off of financing receivables granted to a participated joint
venture to execute an exploration projects that was written-off in
the Black Sea (approximately €270 million), with an additional
effect on the adjusted tax rate due to the fact that these expenses
were non-deductible. The adjusted tax rate for 2018 increased by
approximately 3 percentage points due to the recognition of lower
deferred tax asset relating to certain projects. Excluding these
effects, tax rate decreased by approximately 2 percentage points.
For the full year 2018, taxes paid represented approximately 30%
of the cash flow from operating activities of the E&P segment
before changes in working capital and income taxes paid.
(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 REVIEW
Gas & Power
Operating profit (loss)
Exclusion of inventory holding (gains) losses
Exclusion of special items:
- impairment losses (impairment reversals), net
- environmental charges
- risk provisions
- provision for redundancy incentives
- commodity derivatives
- 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)
(a) Excluding special items.
71
(€ million)
2018
629
(86)
(71)
(1)
122
(156)
112
(92)
543
(4)
9
(238)
43.4
310
2017
75
139
(146)
38
157
(171)
261
214
10
(9)
(163)
75.8
52
2016
(391)
90
(89)
81
1
17
4
(443)
(19)
270
(390)
6
(20)
74
..
(330)
Change
554
% Ch.
..
329
(14)
18
(75)
(32.4)
258
153.7
..
In 2018, the Gas & Power segment reported an adjusted operating
profit of €543 million, the best result of the last eight years, more
than doubled the full year 2017. This improvement reflected the overall
restructuring of all the business lines mainly driven by growth in the
LNG sales, optimizations in the power business and logistics and
favorable trends in the first nine months in the natural gas wholesale
market which enabled the Company to extract value from the
flexibilities associated with the portfolio of long-term supply contracts.
Adjusted operating profit excluded special items of €86 million.
Adjusted net profit was €310 million, improving by €258 million
compared to 2017 when the segment reported an adjusted net
profit of €52 million, due to the better operating performance.
Adjusted tax rate reflected a normalization at 43.4%, decreasing
compared to 75.8% in 2017 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)
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
2016
723
(406)
266
104
104
(8)
28
12
(3)
3
26
583
278
305
1
32
(197)
32.0
419
Change
(1,361)
% Ch.
..
(611)
(141)
(470)
6
(21)
201
4.1
(425)
(61.7)
(26.6)
..
(64.1)
In 2018, the Refining & Marketing segment reported an adjusted
operating profit of €390 million, down by 27% y-o-y driven by lower
refining margins (down by 26%) due to higher petroleum feedstock
cost not recovered in product prices and higher impact from plant
standstills. The oxygenated business was penalized by downtime at
certain assets due to prolonged maintenance activities.
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEWEni Annual Report 2018
72
These negative trends were offset by plant and supply optimizations,
as well as by higher margins on green throughputs. Marketing
activities reported an improved performance both in the retail
and wholesale segments also leveraging on effective commercial
initiatives to support margins and on efficiency actions.
The Chemical business was affected by the worsening trading
environment characterized by sharply higher supply cost of oil-based
feedstock in the first ten months that were not recovered in sale
prices, by competitive pressure and by a demand slowdown in the
last part of the year, mainly in the polyethylene segment, which
resulted in a strong contraction of the benchmark margin of cracker
(down by 11%) and polyethylene margins (down by 69%), as well as,
by the fact that the first half of 2017 benefitted from particularly high
prices of intermediates (butadiene and benzene) due to contingent
factors.
In this scenario, the Chemical business reported breakeven result
and absorbed market fluctuations leveraging on plant optimization
and a shift in its product portfolio towards specialties, which are less
exposed to the scenario volatility. A large-scale change in scenario
affected the petrochemical industry compared to the full year 2017.
Adjusted operating profit of the R&M and Chemicals segment
excluded special items of €526 million and an inventory holding loss
of €234 million.
Adjusted net profit was €238 million decreased by €425 million due
to 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)
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)
2016
(681)
229
88
40
1
7
93
(452)
(721)
(6)
188
(991)
Change
(23)
% Ch.
(3.4)
(64)
2
(17)
155
76
(11.8)
0.3
(77.3)
87.1
7.3
The Corporate and other activities segment mainly includes results
of operations of Eni’s headquarters principally on an intercompany
basis. Eni’s headquarters and certain Eni subsidiaries performs
human resources management, finance, administration, information
technology, legal affairs and other general and business support
services. In addition, this business segment comprises operating
expenses of reclamation and decommissioning activities pertaining
to certain businesses, which Eni exited, divested or shut down in past
years, net of the captive subsidiaries margins related to specialist
business services (insurance, financial and recruitment activities).
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEW
73
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
Inventories - Compulsory stock
Intangible assets
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
Tax payables and provisions for net deferred tax liabilities
Provisions
Other current assets and liabilities
Provisions for employee post-retirement benefits
Assets held for sale including related liabilities
CAPITAL EMPLOYED, NET
Eni shareholders’ equity
Non-controlling interest
Shareholders’ equity
Net borrowings
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
(€ million)
December 31, 2018 December 31, 2017
60,302
1,217
3,170
7,963
1,314
(2,399)
71,567
4,651
9,520
(11,645)
(1,104)
(11,886)
(860)
(11,324)
(1,117)
236
59,362
51,016
57
51,073
8,289
59,362
63,158
1,283
2,925
3,730
1,698
(1,379)
71,415
4,621
10,182
(10,890)
(2,387)
(13,447)
287
(11,634)
(1,022)
236
58,995
48,030
49
48,079
10,916
58,995
Change
(2,856)
(66)
245
4,233
(384)
(1,020)
152
30
(662)
(755)
1,283
1,561
(1,147)
310
(95)
367
2,986
8
2,994
(2,627)
367
(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”.
The Summarized Group Balance Sheet was affected by the
movement in the EUR/USD exchange rate, which determined an
increase in net capital employed, total equity and net borrowings
by €2,107 million, €1,787 million, and €320 million respectively.
This was due to translation into euros of the financial statements
of US-denominated subsidiaries reflecting a 4.5% appreciation of
the US dollar against the euro (1 EUR= 1.146 USD at December 31,
2018 compared to 1.200 at December 31, 2017).
Fixed assets (€71,567 million) increased by €152 million from
December 31, 2017. The item “Property, plant and equipment”
was down by €2,856 million mainly due to the derecognition of
Eni Norge’s assets following loss of control over the subsidiary as
a result of the business combination with Point Resources which
had an offsetting impact in the line-item “Equity-accounted
investments and other investments” mainly due to the
recognition of Vår Energi interest; while DD&A and impairment
losses (€7,854 million) and the disposals were substantially
offset by capital expenditure for the year (€9,119 million). The
increase in the item “Equity-accounted investments and other
investments” of €4,233 million was due to the above mentioned
Vår Energi operation, the new accounting of equity instruments
required by IFRS 9 and the net equity investments. Net payables
related to capital expenditure increased by €1,020 billion due
to the cash-in of the receivables arising from the disposal of the
Zohr interests made in 2017.
Net working capital was in negative territory at minus €11,324
million and increased by €310 million y-o-y driven by the decrease
in risk provisions due to the change of the estimate revision
to the decommissioning provision following higher discount
rates and to tax payables and provision for deferred taxes due
to the derecognition of Eni Norge, offset by a reduction in trade
receivables and an increase in trade payables.
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEWEni Annual Report 2018
74
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
Taxation
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” on equity-accounted entities
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, 2017
Total comprehensive income (loss)
Dividends distributed to Eni’s shareholders
Dividends distributed by consolidated subsidiaries
Other changes
Total changes
Shareholders’ equity at December 31, 2017
attributable to:
- Eni’s shareholders
- Non-controlling interest
Shareholders’ equity at December 31, 2017
Impact of adoption IFRS 9 and IFRS 15
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
(€ million)
2018
4,137
(2)
(15)
15
(2)
1,578
1,787
(243)
(24)
58
1,576
5,713
2017
3,377
(4)
(33)
29
(5,514)
(5,573)
(5)
(6)
69
1
(5,518)
(2,141)
5,702
11
(2,144)
3
(2,141)
(2,881)
(3)
18
5,713
(2,953)
(3)
(8)
53,086
(5,007)
48,079
48,030
49
48,079
245
48,324
2,749
51,073
51,016
57
Shareholders’ equity including non-controlling interest was
€51,073 million, up by €2,994 million. This was due to net profit
for the period and positive foreign currency translation differences
(€1,787 million) reflecting the appreciation of dollar compared to
the euro (up by 4.5%; EUR/USD exchange rate of 1.146 at December
31, 2018 compared to 1.200 at December 31, 2017), partly offset
by a negative change in the fair value of the cash flow hedge reserve
(€243 million) and the distribution of dividend (€2,953 million):
2017 balance dividend of €1,440 million and 2018 interim dividend
for €1,513 million.
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEW
75
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 monitors
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.
(€ million)
Total debt:
Short-term debt
Long-term debt
Cash and cash equivalents
Securities held for trading and other securities held for non-operating purposes
Financing receivables for non-operating purposes
Net borrowings
Shareholders’ equity including non-controlling interest
Leverage
Gearing
December 31, 2018 December 31, 2017
24,707
4,528
20,179
(7,363)
(6,219)
(209)
10,916
48,079
0.23
0.18
25,865
5,783
20,082
(10,836)
(6,552)
(188)
8,289
51,073
0.16
0.14
Change
1,158
1,255
(97)
(3,473)
(333)
21
(2,627)
2,994
0.07
(0.05)
Net borrowings at December 31, 2018 was €8,289 million, lower
by €2,627 million from 2017. Total debt of €25,865 million
consisted of €5,783 million of short-term debt (including the
portion of long-term debt due within twelve months of €3,601
million) and €20,082 million of long-term debt.
This reduction was driven by net cash flow from operations and
the finalization of portfolio transactions as part of the
Dual Exploration Model and other minor assets.
As of December 31, 2018, the ratio of net borrowings to
shareholders’ equity including non controlling interest – leverage
– was 0.16, reporting a decrease from 0.23 as of the end of 2017.
This decline was driven by lower net borrowing and by the increase
in the Group total equity of €2,994 million from December 31, 2017.
This was due to the positive foreign currency translation differences
(€1,787 million) and profit for the year, partly offset by dividend
distribution to Eni’s shareholders (2017 balance dividend and 2018
interim dividend of €2,953 million).
As of December 31, 2018, gearing – the ratio of net borrowings
to net capital employed – was 0.14, lower than 0.18 at December
31, 2017.
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEWEni Annual Report 2018 76
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, taxes paid, interests (paid) received during the period
Net cash provided by operating activities
Capital expenditure
Investments and purchase of consolidated subsidiaries and businesses
Disposals
Other cash flow related to capital expenditure, investments and disposals
Free cash flow
Borrowings (repayment) of debt related to financing activities(b)
Changes in short and long-term financial debt
Dividends paid and changes in non-controlling interests and reserves
Effect of changes in consolidation, exchange differences and cash
NET CASH FLOW
Change in net borrowings
Free cash flow
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
(€ million)
2018
4,137
2017
3,377
2016
(1,044)
Change
760
7,657
(474)
6,168
1,632
(5,473)
13,647
(9,119)
(244)
1,242
942
6,468
(357)
320
(2,957)
18
3,492
2018
6,468
(18)
(499)
(367)
(2,957)
2,627
8,720
(3,446)
3,650
1,440
(3,624)
10,117
(8,681)
(510)
5,455
(373)
6,008
341
(1,712)
(2,883)
(65)
1,689
7,773
(48)
2,229
2,112
(3,349)
7,673
(9,180)
(1,164)
1,054
465
(1,152)
5,271
(766)
(2,885)
(3)
465
2017
6,008
2016
(1,152)
261
474
(2,883)
3,860
5,848
284
(2,885)
2,095
(1,063)
2,972
2,518
192
(1,849)
3,530
(438)
266
(4,213)
1,315
460
(698)
2,032
(74)
83
1,803
Change
460
(18)
(760)
(841)
(74)
(1,233)
(€ million)
(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”.
(b) The item included investments and divestments (on net basis) in held-for-trading financial assets and other investments/divestments in certain short-term financial
assets. Due to their nature and the circumstance that they are very liquid, these financial assets are netted against finance debt in determing net borrowings. Cash flows of such
investments were as follows:
Financing investments:
- securities
- financing receivables
Disposal of financing investments:
- securities
- financing receivables
Borrowings (repayment) of debt related to financing activities
2018
2017
2016
Change
(424)
(196)
(620)
46
217
263
(357)
(316)
(72)
(388)
(1,317)
(272)
(1,589)
223
506
729
341
6,860
6,860
5,271
(108)
(124)
(232)
(177)
(289)
(466)
(698)
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEW
77
Cash flow from operating activities amounted to €13,647 million for
the full year of 2018 was up by 35% driven by an improved underlying
performance and scenario effects.
Cash flow from operating activities for the full year of 2018 was
influenced by a lower level of receivables due beyond the end of the
reporting period being sold to financing institutions, compared to 2017
(approximately €280 million).
Adjusted net cash flow from operating activities before
changes in working capital at replacement cost was €12,662
million, up by 37% y-o-y. This adjusted measure is derived by
excluding certain non-recurring charges: an expense recognized
in connection with the final outcome of an arbitration proceeding
(€313 million), an extraordinary allowance for doubtful
accounts in the E&P segment (€158 million) and an expense
related to the sale of a 10% interest in the Zohr project due to the
fact that they related to the asset disposals (see the following
reconciliation table).
Full Year 2018
(€ million)
k
c
o
t
s
n
o
s
s
o
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/
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fi
o
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n
a
f
o
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a
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a
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a
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a
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i
d
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o
a
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E
r
o
f
e
c
n
a
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%
0
1
n
o
e
u
d
e
s
n
e
p
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E
l
a
s
o
p
s
i
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d
n
u
f
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-
d
e
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s
a
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o
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p
r
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o
Z
e
h
t
s
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c
n
a
v
d
a
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d
a
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T
s
e
r
u
s
a
e
m
P
A
A
G
Net cash before changes in working capital
12,015
96
313
158
80
12,662
Changes in working capital
1,632
(96)
(313)
(158)
(280)
785
Net cash provided by operating activities
13,647
80
(280)
13,447
S
E
R
U
S
A
E
M
P
A
A
G
-
N
O
N
Adjusted net cash
before changes in
working capital
Underlying net cash
provided by
operating activities
Capital expenditure for the year, including investments, was
€9,363 million. Net capex amounted to approximately €7.94
billion and excluded the following items: entry bonus paid
mainly in connection with the two new producing Concession
Agreements in the United Arab Emirates (€869 million); non-
strategic acquisitions in the gas mid-downstream business
(approximately €100 million); the capex pertaining to a 10%
divested interest in the Zohr project (€170 million) incurred
from January 1, 2018 to the closing of the transaction (end
of June 2018), which were reimbursed to Eni by the buyer.
Additionally, as part of the financing agreements with the
Egyptian partners relating to the Zohr project, the Company
cashed in €280 million as an advance on future gas supplies
to Egyptian state-owned companies. In 2018, the self-financing
ratio of net capex was 172%.
Cash flow from disposals (€1,242 million) related to the sale of the
above mentioned 10% interest in the Zohr project, the divestment
of certain other non-strategic assets in the E&P segment and
the gas distribution activity in Hungary. Proceeds from disposals
were netted by Eni Norge’s cash deposited at third-party banks
(approximately €250 million), which was divested as part of the
business combination with Point Resources which determined the
loss of Eni’s control on its former subsidiary.
Other cash flow relating to capital expenditure, investments and
disposals (€942 million) included the collection of the deferred
tranches of the consideration on the sale of 10% and 30% interests
in the Zohr project finalized in 2017 (€450 million) and increased
payables relating to capital expenditure.
In order to calculate cash neutrality, management have reclassified
tha main cash flow metrics.
Excluding from the cash flow, the trade advances cashed-in to
fund the Zohr project and the expense due on 10% of Zohr disposal,
at a Brent price of 71 $/barrel in 2018, adjusted cash flow from
operations amounted to approximately €13.45 billion and positive
changes in receivables and payables associated with investing
activities (mainly including the cash-in of the deferred price of
the Zohr disposals made in 2017) amounted to €0.9 billion. Those
inflows funded capex of €7.94 billion and the dividend of €2.95
billion, leaving a surplus of around €3.5 billion. Consequently, on the
basis of the Group’s cash flow sensitivity to the Brent scenario which
assumes a change of approximately €0.19 billion in cash flow for
each one-US dollar change in the Brent price (and vice versa),
the cash neutrality for funding FY capex and the floor dividend
would have been achieved at 52 $/barrel. This is re-determined in
55 $/barrel when excluding from cash inflows the deferred tranches
of the consideration on the disposal of Eni’s interests in Zohr
made in 2017 (€450 million), being these the unique non-organic
components of the cash flow.
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEWEni Annual Report 2018
78
Capital expenditure
Exploration & Production
- acquisition of proved and unproved properties
- exploration
- development
- other expenditure
Gas & Power
Refining & Marketing and Chemicals
- Refining & Marketing
- Chemicals
Corporate and other activities
Impact of unrealized intragroup profit elimination
Capital expenditure
(€ million)
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
2016
8,254
2
417
7,770
65
120
664
421
243
55
87
9,180
Change
162
864
21
(730)
7
73
148
200
(52)
56
% Ch.
2.1
..
4.8
(10.1)
12.5
51.4
20.3
38.0
(25.6)
64.4
438
5.0
In the full year of 2018, capital expenditure amounted to
€9,119 million (€8,681 million in the FY 2017) and mainly
related to:
- development activities (€6,506 million) deployed mainly
in Egypt, Ghana, Norway, Libya, Italy, Nigeria, Congo and
Iraq. The acquisition of proved and unproved reserves of
€869 million relates to the entry bonus in two producing
Concession Agreements and the offshore concession of
Ghasha in the United Arab Emirates;
- refining activity in Italy and outside Italy (€587 million)
mainly aimed at reconstruction works of the EST conversion
plant at the Sannazzaro refinery, reconversion of Gela
refinery into a biorefinery, 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 retail network of refining product
in Italy and in the rest of Europe (€139 million);
initiatives relating to gas marketing (€161 million) and
power business (€46 million).
-
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEW
79
Alternative performance measures (Non-GAAP measure)
Management evaluates underlying business performance on
the basis of Non-GAAP financial measures, not determined in
accordance with IFRS (“Alternative performance measures”),
such as adjusted operating profit and adjusted net profit, which
are arrived at by excluding from reported operating profit and
net profit certain gains and losses, defined special items, which
include, among others, asset impairments, gains on disposals,
risk provisions, restructuring charges and, in determining the
business segments’ adjusted results, finance charges on finance
debt and interest income (see below). In determining adjusted
results, also inventory holding gains or losses are excluded from
base business performance, which 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, except in
those business segments where inventories are utilized as a
lever to optimize margins. Management is disclosing Non-GAAP
measures of performance 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 Annual Report.
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; or (iii) 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. Those items 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 exchange rate market. As provided for in
Decision No. 15519 of July 27, 2006 of the Italian market regulator
(CONSOB), non-recurring material income or charges are to be
clearly reported in the management’s discussion and financial
tables. Also, special items allow to allocate to future reporting
periods gains and losses on re-measurement at fair value of
certain non-hedging commodity derivatives and exchange rate
derivatives relating to commercial exposures, lacking the criteria
to be designed as hedges, including the ineffective portion of
cash flow hedges and certain derivative financial instruments
embedded in the pricing formula of long-term gas supply
agreements of the Exploration & Production segment.
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 net
capital employed and measures how much of net capital employed
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.
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEWEni Annual Report 2018 80
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 not related to operations. Financial
activities are qualified as “not related to operations” when these
are not strictly related to the business operations.
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/EBITDA adjusted 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 to
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 and gas development activities,
calculated as the ratio between operating costs (as defined by
FASB Extractive Activities - oil&gas Topic 932) and production sold.
ROACE (Return On Average Capital Employed) adjusted
Is the return on average capital invested, calculated as the ratio
between net income before minority interests, 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.
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).
Current ratio
Measures the capability of the company to repay short-term
debt, calculated as the ratio between current assets and current
liabilities.
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 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
s
e
i
t
i
v
i
t
c
a
r
e
h
t
o
d
n
a
e
t
a
r
o
p
r
o
C
(691)
23
18
(1)
(1)
(1)
47
85
(606)
(697)
5
333
(965)
d
e
z
i
l
a
e
r
n
u
f
o
t
c
a
p
m
I
t
fi
o
r
p
p
u
o
r
g
a
r
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.
81
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 2018
82
(€ million)
s
e
i
t
i
v
i
t
c
a
r
e
h
t
o
d
n
a
e
t
a
r
o
p
r
o
C
(668)
26
25
(1)
82
(2)
(4)
126
(542)
(699)
22
178
d
e
z
i
l
a
e
r
n
u
f
o
t
c
a
p
m
I
t
fi
o
r
p
p
u
o
r
g
a
r
t
n
i
n
o
i
t
a
n
m
i
i
l
e
(27)
(6)
(33)
17
(1,041)
(16)
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
981
(213)
136
54
(13)
(6)
(11)
(9)
72
223
991
5
19
(352)
34.7
663
r
e
w
o
P
&
s
a
G
75
(146)
38
157
(171)
261
139
214
10
(9)
(163)
75.8
52
n
o
i
t
c
u
d
o
r
P
&
n
o
i
t
a
r
o
l
p
x
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
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.
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEW
83
n
o
i
t
c
u
d
o
r
P
&
n
o
i
t
a
r
o
l
p
x
E
2,567
(684)
7
(2)
105
24
19
(3)
461
(73)
2,494
(55)
68
(1,999)
79.7
508
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
723
(406)
104
104
(8)
28
12
(3)
3
26
266
583
1
32
(197)
32.0
419
r
e
w
o
P
&
s
a
G
(391)
90
1
81
17
4
(443)
(19)
270
(89)
(390)
6
(20)
74
18.3
(330)
r
e
h
t
o
d
n
a
e
t
a
r
o
p
r
o
C
s
e
i
t
i
v
i
t
c
a
(681)
88
40
1
7
93
229
(452)
(721)
(6)
188
d
e
z
i
l
a
e
r
n
u
f
o
t
c
a
p
m
I
t
fi
o
r
p
p
u
o
r
g
a
r
t
n
i
n
o
i
t
a
n
m
i
i
l
e
(61)
141
80
(19)
(991)
61
D
E
U
N
I
T
N
O
C
S
I
D
S
N
O
I
T
A
R
E
P
O
413
(413)
I
G
N
U
N
I
T
N
O
C
S
N
O
I
T
A
R
E
P
O
2,157
(175)
193
(459)
7
(10)
151
47
(427)
(19)
850
333
2,315
(769)
74
(1,953)
120.6
(333)
7
(340)
(1,051)
(120)
831
(340)
P
U
O
R
G
2,157
(175)
193
(459)
7
(10)
151
47
(427)
(19)
850
333
2,315
(769)
74
(1,953)
120.6
(333)
7
(340)
(1,464)
(120)
1,244
(340)
(€ million)
2016
Reported operating profit (loss)
Exclusion of inventory holding (gains) losses
Exclusion of special items:
- environmental charges
- impairment losses (impairments reversal), net
- write off
- 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 REVIEWEni Annual Report 2018
84
Reconciliation of Summarized Group Balance Sheet
and Statement of Cash Flows to Statutory Schemes
Summarized Group Cash Flow Statement
Items of Summarized Group Balance Sheet
(where not expressly indicated the item derives
directly from the statutory scheme)
December 31, 2018
December 31, 2017
Notes to the
Consolidated
Financial
Statement
Partial
amounts
from
statutory
scheme
Amounts
of the
summarized
Group scheme
Partial
amounts
from
statutory
scheme
Amounts
of the
summarized
Group
scheme
(€ million)
Fixed assets
Property, plant and equipment
Inventories - Compulsory stock
Intangible assets
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 capital expenditure/disposals non-current
- payables related to capital expenditure
Total fixed assets
Net working capital
Inventories
Trade receivables
Trade payables
Tax payables and provisions for net deferred tax liabilities, made up of:
- income tax payables
- other tax payables
- deferred tax liabilities
- other non-current tax liabilities
- current tax assets
- other current tax assets
- deferred tax assets
- other non-current tax assets
- payables/receivables 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 post-retirements benefits
Assets held for sale including related liabilities
made up of:
- assets held for sale
- liabilities related to assets 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 financial liabilities
less:
Cash and cash equivalents
Securities held for trading and other securities held
for non-operating purposes
Financing receivables for non-operating purposes
Total net borrowings(a)
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
(see note 15)
(see note 7)
(see note 10)
(see note 16)
122
9
(2,530)
(see note 7)
(see note 16)
(see note 17)
(see note 10)
(see note 16)
(see note 15)
(see note 7)
(see note 10)
(440)
(1,432)
(4,272)
(61)
191
561
3,931
422
(4)
51
4,459
2,258
361
(see note16)
(2,568)
(see note 17)
(3,980)
(1,441)
295
(59)
20,082
3,601
2,182
(see note 6)
(see note 15)
60,302
1,217
3,170
7,963
1,314
(2,399)
71,567
4,651
9,520
(11,645)
(1,104)
(11,886)
(860)
(11,324)
(1,117)
236
59,362
51,073
25,865
(10,836)
(6,552)
(188)
8,289
59,362
597
118
(2,094)
(472)
(1,472)
(5,900)
(45)
191
729
4,078
507
(3)
84
4,641
1,573
698
(3,760)
(1,515)
(1,434)
323
(87)
20,179
2,286
2,242
63,158
1,283
2,925
3,730
1,698
(1,379)
71,415
4,621
10,182
(10,890)
(2,387)
(13,447)
287
(11,634)
(1,022)
236
58,995
48,079
24,707
(7,363)
(6,219)
(209)
10,916
58,995
(a) For details on net borrowings see also note 19 to the condensed consolidated interim financial statements.
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEW 85
Summarized Group Cash Flow Statement
Items of Summarized Cash Flow Statement and
confluence/reclassification of items in the statutory scheme
2018
2017
Partial amounts
from statutory
scheme
Amounts of the
summarized
Group scheme
Partial amounts
from statutory
scheme
Amounts of the
summarized
Group scheme
(€ million)
Net profit (loss)
Adjustments to reconcile net profit (loss) to cash provided by operating
activities:
Depreciation, depletion and amortization and other non monetary items
- depreciation, depletion and amortization
- impairment losses (impairment reversals), 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 for contingencies
- other assets and liabilities
4,137
7,657
(474)
6,168
1,632
3,377
8,720
(3,446)
3,650
1,440
7,483
(225)
263
267
894
38
(205)
(283)
671
3,467
(346)
657
284
96
749
6,988
866
100
68
(474)
109
(231)
(185)
614
5,970
15
334
642
(238)
879
Dividends received, taxes paid, interest (paid) received during the period
(5,473)
(3,624)
- dividends received
- interest received
- interest paid
- income taxes paid, net of tax receivables received
Net cash provided by operating activities
Investing activities:
- tangible 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
- changes in consolidated subsidiaries and businesses net
of cash and cash equivalent disposed of
- income taxes paid on disposals
- investments
Other cash flow related to capital expenditure, investments and disposals
- securities
- financing receivables
- change in payables in relation to investing activities
and capitalized depreciation
reclassification: purchase of securities and financing receivables
held for non-operating purposes
- disposal of securities
- disposal of financing receivables
- change in receivables in relation to disposals
reclassification: disposal of securities and financing receivables held
for non-operating purposes
Free cash flow
10,117
(8,681)
(510)
5,455
(373)
275
87
(609)
(5,226)
(8,778)
(341)
(125)
(119)
1,089
5
(47)
195
(432)
(554)
408
620
61
496
606
(263)
13,647
(9,119)
(244)
1,242
942
291
104
(582)
(3,437)
(8,490)
(191)
(510)
2,745
2
2,662
(436)
482
(316)
(657)
152
388
224
999
(434)
(729)
6,468
6,008
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEWEni Annual Report 2018 86
continued Summarized Group Cash Flow Statement
Items of Summarized Cash Flow Statement and
confluence/reclassification of items in the statutory scheme
2018
2017
Partial amounts
from statutory
scheme
Amounts of the
summarized
Group scheme
Partial amounts
from statutory
scheme
Amounts of the
summarized
Group scheme
(€ million)
Free cash flow
Borrowings (repayment) of debt related to financing activities
reclassification: purchase of securities and financing receivables held for
non-operating purposes
reclassification: disposal of securities and financing receivables held for
non-operating purposes
Changes in short and long-term finance debt
- increase in long-term finance debt
- repayments of long-term finance debt
- increase (decrease) in short-term finance debt
Dividends paid and changes in non-controlling interest and reserves
- dividends paid by Eni to shareholders
- dividends paid to non-controlling interest
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 cash flow
(620)
263
3,790
(2,757)
(713)
(2,954)
(3)
18
6,468
(357)
320
(2,957)
18
3,492
(388)
729
1.842
(2,973)
(581)
(2,880)
(3)
(72)
7
6,008
341
(1,712)
(2,883)
(65)
1,689
FINANCIAL REVIEW AND OTHER INFORMATION | FINANCIAL REVIEW
87
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.
Eni’s operating results, cash flow and rates of growth are
affected by volatile prices of crude oil, natural gas, oil products
and chemicals
Prices of oil and natural gas have a history of volatility due
to many factors that are beyond Eni’s control. These factors
include among other things:
- global and regional dynamics of oil and gas supply and
demand and global level of inventories. In 2018, the oil market
environment was a volatile one. Until October 2018, crude oil
prices continued the upward trend commenced in the second
half of 2017 driven by economic growth, effectiveness of
the production cuts implemented by OPEC Countries and
other producers agreed at the end of November 2016 and
normalizing inventory level. Geopolitical risks also played a
role including production disruption in Venezuela, renewed
internal tensions in Libya and worsening relations between
USA and Iran. Oil prices peaked in October 2018, touching
a four-year high around 85 $/bbl for the Brent crude oil
benchmark. Then in November 2018, a sharp downturn, one
of the steepest on record, followed driving crude oil prices as
low as 60 $/bbl, a correction of about 30%. This downturn was
driven by emerging trends pointing to an economic slowdown,
uncertainties relating to the developments of the USA-China
trade dispute and of the Brexit, and building oversupplies
due to rising production levels in USA, OPEC and Russia also
in anticipation of the enactment of US sanctions against
Iran, which would happen to be less severe than expected.
In December 2018, OPEC and Russia agreed to cut again
production quotas by 1.2 million bbl/d, effective from January
2019, in an effort to curb a supply glut. In spite of this
development, crude oil prices continued to slide throughout
December 2018 to the year’s lows of 50 $/bbl, extending the
correction from the highs to 40%. On average, in 2018 the
price for the Brent crude oil benchmark increased by 31%
y-o-y at about 71 $/bbl.
In early 2019, oil prices regained the sixty-dollar mark thanks
to better-than-expected gauges of economic activity and
implementation of the production cuts. In the first quarter
of 2019, the Brent crude oil price averaged approximately 63
$/bbl pointing to renewed strength;
- global political developments, including sanctions imposed
on certain producing Countries and conflict situations;
- global economic and financial market conditions;
- the ability of the OPEC cartel to control world supply and
therefore oil prices;
- prices and availability of alternative sources of energy (e.g.,
nuclear, coal and renewables);
- weather conditions;
- operational issues;
- governmental regulations and actions;
- success in the development and deployment of new
technologies for the recovery of crude oil and natural gas
reserves and technological advances affecting energy
consumption;
- competition from alternative energy sources like solar
energy, photovoltaic and other renewables;
- rising commitment of the world nations and the civil society
to addressing the issue of global warming and climate change
by reducing the release in the atmosphere of greenhouse
gases (“GHG”) produced by the consumption of hydrocarbons
in human activities.
All these factors can affect the global balance between demand
and supply for hydrocarbons and hence prices of crude oil,
natural gas, and other energy commodities.
Management expects global oil demand to grow by
approximately 1.4 mmbbl/d in 2019, more or less in line with
2018, and global oil demand and supplies to be balanced
overall. Considering the risks of an economic slowdown,
geopolitical factors, uncertainties associated with possible
developments in the USA-China trade dispute and with the
Brexit, management is assuming a Brent price of 62 $/bbl in
2019, gradually increasing over the following three year period
to reach 70$/bbl in 2022. After 2022, management is assuming
a price growing in line with inflation (e.g. 71.4 $/bbl in 2023
assuming a long-term inflationary rate of 2%) based on its
view of market fundamentals and oil price projections made
by specialized agencies and financial analysts, substantially
in line with the previous planning assumptions. Management’s
oil price forecast was utilized to elaborate the Group financial
projections and the level of Group’s capital expenditures for
the 2019-2022 industrial plan and to estimate recoverability
of the carrying amounts of the Group’s oil and gas assets as of
December 31, 2018.
Fluctuations in oil and natural gas prices materially affect the
Group’s results of operations and business prospects. Lower
prices from one year to another negatively affect the Group’s
consolidated results of operations and cash flow. This is
because lower prices translate into lower revenues recognized
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 €190 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 2019 at 62
$/bbl. Furthermore, a structural decline in commodity prices
may have material effects on Eni’s business outlook and may
limit the Group’s funds available to finance expansion projects
and certain contractual commitments. This because lower oil
and gas prices over prolonged periods may adversely affect the
88
funds available to finance expansion projects, further reducing
the Company’s ability to grow future production and revenues.
In addition, in a weak scenario 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.
In case of a structural decline in hydrocarbons prices, the
Company may review the carrying amounts of oil and gas
properties and this could result in recording material asset
impairments. Finally, lower oil and gas prices could result in
the de-booking of proved reserves, if they become uneconomic
in this type of environment. These risks may adversely impact
the Group’s results of operations, cash flow, liquidity, business
prospects and shareholder returns, including dividends and the
share prices.
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, including Standard & Poor’s Ratings Services
(“S&P”) and Moody’s Investor Services Inc (“Moody’s”). 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.
Eni is estimating 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 characterized by a
sizeable presence of production sharing contracts, whereby,
due to the cost recovery mechanism, the Company is entitled
to a larger number of barrels in the event of a fall in crude oil
prices. (See the specific risks of the Exploration & Production
segment in “Risks associated with the exploration and
production of oil and natural gas” below).
-
The Group’s results from its Refining & Marketing and Chemicals
businesses are primarily dependent upon the supply and
demand for refined and chemical products and the associated
margins on refined products and chemical products sales, with
the impact of changes in oil prices on results of these segments
being dependent upon the speed at which the prices of products
adjust to reflect movements in oil prices.
Because of the above mentioned risks, a prolonged decline
in commodity prices would materially and adversely affect
the Group’s business prospects, financial condition, results
of operations, cash flows, ability to finance planned capital
expenditures and commitments and may impact shareholder
returns, including dividends and the share price.
Competition
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 characterized 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 cost, efficient management of capital
resources and the ability to provide valuable services to the
energy buyers. It also depends on Eni’s ability to gain access to
new investment opportunities, both in Europe and worldwide.
-
In the Exploration & Production segment, Eni faces
competition from both international and state-owned oil
companies for obtaining exploration and development
rights, and developing and applying new technologies to
maximize hydrocarbon recovery. Furthermore, Eni may face a
competitive disadvantage because of its smaller size relative
to other international oil companies, particularly 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. If, because of those competitive pressures, Eni
fails to obtain new exploration and development acreage, to
apply and develop new technologies, and to control costs, its
growth prospects and future results of operations and cash
flow in this business may be adversely affected.
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 fueled 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. Management believes that competition
in the European wholesale gas market will continue to
negatively affect the results of operations and cash flow of
Eni’s Gas & Power segment in future reporting periods. 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 areas 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
FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIES
market is characterized by strong competition among local
selling companies which mainly compete in term of pricing
and the ability to bundle valuable services with the supply
of the energy commodity. In this segment competition
has intensified in recent years due to the progressive
liberalization of the market and the option on part of
residential customers to switch smoothly from one supplier to
another. Management believes that competition will represent
a risk factor to the Company’s results of operations and cash
flow in this business unit.
- Eni is facing strong competitive pressure in its business
of gas-fired electricity generation which is largely sold at
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. This latter
was due to the fact that power produced from renewable
sources and coal-fired power generation are cheaper than
gas-fired electricity, although coal-fired plants are expected
to be progressively phased-out due to environmental
issues. Management believes that these negative 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 faces strong
-
competition both in the wholesale markets and in the retail
marketing activity. Margins of European refiners are facing
structural headwinds due to muted trends in the European
demand for fuels and continued competitive pressures
from players in the Middle East, the USA and Asia, who can
leverage on larger plant scale and cost economies, availability
of cheaper feedstock, lower energy expenses and fewer
environmental obligations. Eni believes that the competitive
environment 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. In 2018 Eni’s gauge of profitability in
the refining business fell by approximately 26% to 3.7 $/bbl
driven by rising costs of oil-based feedstock that the Company
was unable to transfer to final products prices pressured
by the weak market fundamentals described above. This
decline negatively affected the performance of the Company’s
refining activity. Management believes that in the long-term
the trading environment will not recover meaningfully with
refining margins seen in a 4-5 $/bbl range. Furthermore, Eni’s
refining margins are exposed to the volatility in the spreads
between crudes with high sulfur content or sour crudes vs. the
Brent crude benchmark, which is a low-content sulfur crude.
Eni complex refineries are able to process sour crudes which
typically trade at a discount over the Brent crude. However,
in 2019 a shortfall in supplies of sour crudes is expected in
the market due to the production cuts implemented by OPEC,
lower exports from Venezuela and the USA sanctions against
Iran. Those developments could result in an appreciation of
the relative prices of sour crudes vs. the Brent, which would
negatively affect the results of our refining business. Against
this backdrop, management has designed an action plan
89
intended to reduce the Company’s breakeven margin in its
refining business to about 3 $/bbl in 2019 by means of plant
and feedstock optimization, energy savings and other cost
efficiencies. Additionally, management expects to close by
year-end the acquisition of a 20%-stake in a large refining
asset in Abu Dhabi, which will de-risk Eni’s refining business
due to the fact that the asset being acquired is more profitable
than Eni’s legacy refineries due to larger scale, efficiency,
geographic reach and proximity to raw materials sources. In
case management fails to execute on this plan, the profitability
of Eni’s refining business may be negatively affected
considering management’s expectations for a weak trading
environment. In marketing, Eni faces competition from other
oil companies and newcomers such as low-scale operators and
large retailers, who tend to adopt aggressive pricing policies. All
these operators compete with each other primarily in terms of
pricing and, to a lesser extent, service quality.
In the Chemical business, Eni faces strong competition from
well-established international players and state-owned
petrochemical companies, particularly in the most
commoditized market segments such as the production
of basic petrochemical products (like ethylene and
polyethylene), which demand is a function of macroeconomic
growth. Many of those 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
capacity across Europe has also fueled 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 utilized by Eni’s petrochemicals
subsidiaries. In 2018 the operating profit of our Chemicals
business fell sharply due to increased expenses for oil-
based feedstock, which the Company was not able to pass
to final products prices pressured by competition. The
Company does not expect any meaningful improvement in
the trading environment in the short to the medium-term
due to competitive headwinds described above. Management
intends to execute an action plan designated to diversify the
product portfolio away from the more commoditized products
which are exposed to crude oil prices fluctuations and
cyclical market dynamics and to focus on higher-value added
products, particularly in the green chemicals business and in
specialty niche markets, which we believe are less exposed
to the economic cycle and to the volatility of crude oil prices.
If the Company fails to reduce its exposure to commodity
plastics and to gain critical mass in the green chemicals
business and in the specialty markets, its future results of
operations and cash flows may remain cyclical and exposed
to any demand or cost downturn.
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,
FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIESEni Annual Report 2018 90
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, malfunction of plants,
equipment and facilities, control systems failure, human errors,
acts of sabotage, loss of containment and adverse weather
events can trigger damaging events such as explosions, fires,
oil and gas spills from wells, pipeline and tankers, release of
contaminants, 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 mitigate 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 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. Accidents at a single well can lead to
loss of life, damage or destruction to properties, environmental
damage, GHG emissions and consequently potential economic
losses that could have a material and adverse effect on the
business, results of operations, liquidity, reputation and
prospects of the Group, including its share price and dividends.
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
and the environment.
The Company has invested and will continue to invest
significant resources in order to upgrade the methods and
systems for safeguarding safety and health of employees,
contractors and 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
minimize 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. 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
resulting in personal injury, loss of life, environmental damage,
legal liabilities and/or damage claims, destruction of crude oil
or natural gas wells, as well as damage to equipment and other
property, all of which could lead to a disruption in operations
and to negatively affect results and cash flow and the
Company’s business prospects.
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
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 unfavorable events and in connection
with environmental clean-up and remediation. Maximum
compensation is $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.
FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIES 91
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 events could have a
material adverse impact on the Group’s business, competitive
position, cash flow, results of operations, liquidity, future
growth prospects and shareholders’ returns and damage the
Group’s reputation.
Risks associated with the exploration and production of oil
and natural gas
The exploration and production of oil and natural gas require
high levels of capital expenditures and are subject to natural
hazards and other uncertainties, including those relating to the
physical characteristics of oil and gas fields. The exploration
and production activities are subject to the mining risk and the
risks of cost overruns and delayed start-up at the projects to
develop and produce hydrocarbons reserves. Those risks could
have an adverse, significant impact on Eni’s future growth
prospects, results of operations, cash flows, liquidity and
shareholders’ returns.
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, income taxes and taxes on production,
environmental protection measures, control over the
development and abandonment of fields and installations, and
restrictions on production. A description of the main risks facing
the Company’s business in the exploration and production of oil
and gas is provided below.
Eni’s oil and natural gas offshore operations are particularly
exposed to health, safety, security and environmental risks
Eni has material offshore operations relating to the exploration
and production of hydrocarbons. In 2018, approximately 56%
of Eni’s total oil and gas production for the year derived from
offshore fields, mainly in, Libya, Norway, Angola, Egypt, the Gulf
of Mexico, Italy, Congo, Indonesia, Venezuela, the United Arab
Emirates, the United Kingdom and Nigeria. 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. Failure to manage
these risks could result in injury or loss of life, damage
to property or environmental damage, and could result in
regulatory action, legal liability, loss of revenues and damage
to Eni’s reputation and could have a material adverse effect on
Eni’s future growth prospects, results of operations, cash flows,
liquidity, reputation and shareholders’ returns.
Exploratory drilling efforts 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 financial risks associated with these
activities. Because Eni plans to make significant investments in
executing exploration projects, 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 growth prospects, results of operations,
cash flows and liquidity.
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,
governments and state-owned companies, suppliers,
customers or others to define project terms and conditions,
including, for example, Eni’s ability to negotiate favorable
long-term contracts to market gas reserves;
- commercial arrangements for pipelines and related
equipment to transport and market hydrocarbons;
- timely issuance of permits and licenses by government
agencies;
- the ability to make 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
FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIESEni Annual Report 2018 92
complex offshore units such as FPSO and platforms are built;
these events may cause cost overruns and delays impacting
the time-to-market of the reserves;
- risks associated with the use of new technologies and the
inability to develop advanced technologies to maximize
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.
As previously described, events such as poor project execution,
inadequate front-end engineering design, delays in the
achievement of critical phases and project milestones, delays
in the delivery of production facilities and other equipment
by third parties, differences between scheduled and actual
timing of the first oil, as well as cost overruns may adversely
affect the economic returns of Eni’s development projects.
Failure to deliver major projects on time and on budget could
negatively affect results of operations, cash flow and the
achievement of short-term targets of production growth. Lastly,
the development and marketing of hydrocarbon reserves
typically require several years after a discovery is made. This
is because a development project involves an array of complex
and lengthy activities, including appraising a discovery in
order to evaluate the technical and economic feasibility of the
development project, project final investment decision and
building and commissioning the related plants and facilities.
As a consequence, rates of return for such long lead time
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.
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.
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 600 bbl/d for each
$1 change in oil prices based on current Eni’s assumptions for
oil prices. This led to negative reserves revisions of 38 mmBOE
in 2018, due to the oil price increase previously described. 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.
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 and this will negatively
affect future results of operations, cash flow and business
prospects.
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.
Reserve estimates are subject to revisions as prices fluctuate
due to the cost recovery mechanism under the Company’s
FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIES
93
production sharing agreements and similar contractual
schemes.
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 December 31, 2018, average prices
were based on 71.4 $/bbl for the Brent crude oil.
Brent prices have declined significantly since they reached
a peak at 85 $/bbl in October of 2018 and in the first quarter
of 2019 have recovered only partially. If such prices do not
increase significantly in the coming months, our future
calculations of estimated proved reserves will be based on
lower commodity prices which could result in our having to
remove non-economic reserves from our proved reserves in
future periods. This effect could be counterbalanced in full or
in part by increased reserves corresponding to the additional
volume entitlements under Eni’s PSAs relating to cost oil: i.e.
because of lower oil and gas prices, the reimbursement of
expenditures incurred by the Company requires additional
volumes of reserves.
Accordingly, the estimated reserves reported as of the end of
2018 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, which could adversely
impact Eni’s business prospects, results of operations, cash
flows and liquidity.
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, 2018, approximately 32% 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, 2018 includes estimates of total future
development and decomissioning costs associated with
the Group’s proved total reserves of approximately €35.3
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%.
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. Adverse changes in the tax rate
applicable to the Group’s profit before income taxes in its oil and
gas operations would have a negative impact on Eni’s future
results of operations and cash flows.
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 nationalizations and expropriations.
Eni’s results and cash flow depend on its ability to identify and
mitigate the above mentioned risks and hazards which are
inherent to its operations.
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 US 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 the US 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.
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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, 2018, the net present
value of Eni’s proved reserves totaled approximately €57.6
billion. The average prices used to estimate Eni’s proved
reserves and the net present value at December 31, 2018, as
calculated in accordance with US SEC rules, were 71.4 $/bbl for
the Brent crude oil. Actual future prices may materially differ
from those used in our year-end estimates. Commodity prices
have decreased significantly in recent months. Holding all other
factors constant, if commodity prices used in Eni’s year-end
reserve estimates were in line with the pricing environment
existing in the first quarter of 2019, Eni’s PV-10 at December 31,
2019 could 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 and gas operation
with significant effects on the Group business prospects, results
of operations and cash flow.
In Italy, a new law has been enacted effective February 12,
2019, which requires certain Italian administrative bodies to
adopt within eighteen months 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; on the contrary in unsuitable areas,
exploration permits are repealed.
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.
In case Italian administrative bodies fail to adopt the national
plan for suitable areas within two years from the law enactment,
the general moratorium on exploration activities is revoked
and application for new concession permits can be filed.
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.
Our largest development project in Italy is operated under a
concession that will expire in 2019; the application for renewal
is underway and the renewal process is unaffected by the new
law; assuming it is renewed as expected, this concession will
expire in 2029, unless renewed at that time. Production at those
sites is currently scheduled to continue until 2045.
Management believes the criteria laid out in the law for
identified unsuitable areas 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 adoption 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
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 expects any material impacts on the Group future results of
operations and cash flow.
Political considerations
The large majority of Eni’s oil and gas reserves are located
in Countries outside Europe and North America, mainly in
Africa, Central 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 additional risks and uncertainties in addition to the
material risks described above, which could materially impact
the ability of the Company to conduct its oil and gas operations
in a safe, reliable and profitable manner.
As of December 31, 2018, approximately 82% of Eni’s proved
hydrocarbon reserves were located in such Countries. Adverse
political, social and economic developments, such as internal
conflicts, revolutions, establishment of non-democratic
regimes, protests, strikes and other forms of civil disorder,
contraction of economic activity and financial difficulties of the
local governments with repercussions on the solvency of state
institutions, inflation levels, exchange rates and similar events
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95
in those non-OECD Countries 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.
In particular, Eni faces risks in connection with the following,
possible issues:
-
lack of well-established and reliable legal systems and
uncertainties surrounding the enforcement of contractual
rights;
- unfavorable enforcement of laws, regulations and contractual
arrangements leading, for example, to expropriation,
nationalization or forced divestiture of assets and unilateral
cancellation or modification of contractual terms. Eni is facing
increasing competition from state-owned oil companies
that are partnering Eni in a number of oil and gas projects
and properties in the host Countries where Eni conducts its
upstream operations. These state-owned oil companies can
unilaterally change contractual terms and other conditions of
oil and gas projects in order to obtain a larger share of profit
from a given project, thereby reducing Eni’s profit share.
They can also enforce different interpretations of contractual
clauses relating to the recovery of certain expenses incurred
by the Company to produce hydrocarbons reserves in any
given project;
- 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 during the recent, three-year long oil downturn
which ended by mid of 2017. Financial difficulties at country
level often translate into failure on part of state-owned
companies and agencies to fulfill 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);
- political and social instability which could result in civil and
social unrest, internal conflicts and other forms of protest
and disorder 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;
- difficulties in finding qualified suppliers in critical operating
environments; and
- complex processes of granting authorizations 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. 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
Eni’s business, results of operations and financial condition.
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 of 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. In the second
half of 2018 a resurgence of socio-political instability coupled
with internal clashes reduced the Country economic activity and
gas demand which negatively affected the Company’s levels
of production for the year. Management is closely monitoring
the situation and is evaluating any possible measure to
safeguard safety of Eni’s local personnel and security of plants
and production infrastructures. 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. Currently, Libya represents approximately 16%
of the Group’s total production; this proportion is forecasted to
decrease in the medium term. In the event of major adverse
events such as the resumption of internal conflict, acts of
war, sabotage, social unrest, clashes and other forms of civil
disorder, Eni could be forced to interrupt or reduce its producing
activities at the Libyan plants, negatively affecting Eni’s results
of operations, cash flow and business prospects.
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 USA market, which is the main outlet of
Venezuelan production, which are described below. Eni expects
the financial and political outlook of Venezuela to negatively
affect its ability to recover the investments made in the Country
to develop two petroleum projects and the overdue trade
receivables owned to us by the Venezuelan national oil company
– PDVSA – and its affiliates for the gas supplies of the Cardón IV
gas project, a 50% – held joint venture. In 2018, this venture was
able to collect a certain percentage of the sales of the equity gas
produced in the year to PDVSA. The venture is systematically
accounting a loss provision on the uncollected revenues
based on management’s appreciation of the counterparty risk
which was estimated based on the findings of a review of the
past experience of sovereign defaults. Furthermore, due to a
worsening operating environment, management decided to de-
book the proved undeveloped reserves (down 106 million bbl)
at one of the Company’s projects in the Country, recognizing an
impairment loss of around €200 million.
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 and the
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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
jeopardized 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 and other Countries.
It is possible that the Group may incur further asset
impairments or credit losses in future reporting periods
depending on the evolution of the financial outlook of
the Countries where the Group is conducting its Oil & Gas
operations.
In Egypt, Eni plans to invest significantly in the next four-year
plan to sustain the production plateau at the Zohr offshore gas
field and to develop existing gas reserves at other projects.
Since our gas production is entirely sold to local state-owned
oil companies, we expect a significant increase in the credit
risk exposure in Egypt, where we experienced some issues at
collecting overdue trade receivables during the downturn. Eni
will continue monitoring the counterparty risk in future years
considering the significant volumes of gas expected to be
supplied to Egypt’s national oil companies.
Eni closely monitors 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
certain projects and to selectively evaluate projects. While the
occurrence of those events is unpredictable, the occurrence
of any such events could adversely affect Eni’s results from
operations, cash flow and business prospects, also including
the counterparty risk arising from the financing exposure of Eni
in case state-owned entities, which are party to Eni’s upstream
projects for developing hydrocarbons, fail to reimburse due
amounts.
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. Recently, the US Government has 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 US Administration enacted certain financing
sanctions against Venezuela, which prohibit any US 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
US 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 US dealers to trade bonds
issued by the Government of Venezuela and its affiliates. These
sanctions do not affect directly Eni’s activities, which however
are affected by the worsening 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
Until 2018, our Gas & Power segment has recorded a history of
weak profitability and losses due to the changed fundamentals
of the wholesale gas markets in Europe following the gas
downturn of 2013-2014. Competition escalated driven by
muted demand growth, oversupplies and the increasing
weigh in the European energy mix of governmental-subsided
renewable energy sources (particularly the photovoltaic).
The large-scale development of shale gas in the United States
was another factor contributing to the oversupply situation in
Europe, because many LNG projects worldwide that originally
targeted the US market were redirected to an already saturated
European market. Furthermore, a number of re-gasification
terminals in the US have been upgraded to gas liquefaction
facilities with the aim of exporting the US gas surplus. Large
gas supplies to Europe led to the development of liquid spot
markets where gas is traded daily. Prices at those hubs became
the main indexation parameter of selling prices, replacing
prices contractually agreed in bilateral negotiations between
gas buyers and gas wholesalers. Increased competition,
market liquidity and indexation mismatch between gas
purchase prices and selling prices determined a squeeze of
margins on gas sales. These trends were exacerbated by the
contractual commitments taken by the Company to supply gas
to end-markets in Europe. A few years ago, before the onset
of the European gas downturn, the Company signed with the
main Countries supplying gas to Europe (Russia, Algeria, the
Netherlands, Libya and Norway) long-term gas supply contracts
with take-or-pay clauses, which would expose us to a volume
risk, as the Company was contractually required to purchase
minimum annual amounts of gas or, in case of failure, to pay the
corresponding price. Additionally, Eni booked the transportation
rights along the main gas backbones across Europe to deliver
its contracted gas volumes to end-markets. In a weak market,
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97
the need to dispose of the minimum off-take of gas negatively
affected Eni’s margins. Those market trends have negatively
affected the operating performance of our Gas & Power segment
from the beginning of the market crisis throughout 2017,
when this segment closed at breakeven. However, in 2018 the
segment posted a significant recovery in profitability due to
the benefits of the renegotiations of its long-term gas supply
contracts and other drivers. Furthermore, in 2018 gas demand
and supplies in Europe were more balanced due to a certain
recovery in demand supported by the phase out of a number
of coal-fired power plants and lower production from nuclear
plants, a slowdown in the final investment decisions in new
liquefaction capacity due to the oil downturn and increasing gas
demand from China. Looking forward, the Company expects that
a muted demand environment in Europe driven by an ongoing
economic slowdown will increase the risks of oversupplies and
margin pressure.
Against the backdrop of a challenging 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 supply contracts with
take-or-pay clauses and its structure of fixed costs linked to the
transportation rights at the main European backbones booked
for multi-year periods. Such risk factors include continuing
oversupplies, pricing pressures, volatile margins and the risk of
deteriorating spreads of Italian spot prices versus continental
benchmarks. The results of Eni’s wholesale business are
particularly exposed to the volatility of the spreads between
spot prices at European hubs and Italian spot prices because
the Group’s supply costs are mainly linked to prices at European
hubs, whereas a large part of the Group’s selling volumes are
linked to Italian spot prices which, historically, have been
higher due to the costs of logistics and other factors. This price
differential enables the Company to recover its fixed operating
expenses in the gas wholesale business. Risks are raising that
spot prices in Italy could converge with prices at continental
hubs due to the current slowdown of gas demand in Europe and
in Italy and the return of LNG spot volumes at European markets
and also at Italian regasification terminals. Longer-term there
are risks of an oversupply build in the Italian market due to the
expected entry into operations of a project to import gas from
the Caspian region to Italy and other developments. A reduction
of the spread between Italian spot prices and European spot
prices for gas could negatively affect the profitability of our
business by reducing the total addressable market and the
related opportunities to monetize the flexibilities of our gas
portfolio, as in the case of the possibility to lift additional gas
volumes in addition to the annual minimum quantity at our
take-or-pay contracts up the annual contractual quantity in case
of favorable market conditions.
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 and volume terms to current
market conditions as they evolve, 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, the claiming party has
the ability to open an arbitration procedure to obtain revised
contractual conditions. However, the suppliers might also file
counterclaims with the arbitration panel seeking to dismiss
Eni’s request for a price review and may also claim an increase
in the price of the gas supplied to Eni based on their own view
of markets dynamics. All these possible developments within
the renegotiation process could increase the level of risks and
uncertainties relating the outcome of those renegotiations.
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
In the years preceding the European gas downturn of 2013-
2014,
Eni signed a number of 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). These contracts
were intended to secure Eni long-term access to gas supplies,
particularly with a view to supplying the Italian gas market and
in anticipation of certain pargets of gas demand growth, which
however would fall short of industry’s projections.
These contracts 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.
Risks associated with sector-specific regulations in Italy
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
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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.
Environmental, health and safety regulations
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 EU, international, national, regional
and local laws and regulations regarding the impact of its
operations on the environment and health and safety of
employees, contractors, communities and 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
health 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 set limits to the emission of scrap
substances and pollutants and discipline the handling of
hazardous materials and discharges of water contaminants
nad nocive air emissions 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 into the atmosphere, the soil 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 safety in
the workplace and of communities, the Company may be liable
for the negligent or willful conduct on part of its employees as
per Italian Law Decree No. 231/2001, which assumes that any
misconduct of employees in the field of environmental and
health matters can be ascribed to the Company.
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, safety in the workplace, health 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;
- 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 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, which could
diminish Eni’s productivity and materially and adversely impact
Eni’s results of operations, cash flow and liquidity.
Risks of environmental, health and safety incidents and
liabilities are inherent in many of Eni’s operations and products.
Management believes that Eni adopts high operational
standards to ensure safety in running its operations and
safeguard of the environment and the health of employees,
contractors and communities. In spite of such measures, it is
possible that incidents like blowouts, oil spills, contaminations,
pollution, and release in the air, soil and ground water of
pollutants and other dangerous materials, liquids or gases,
and other similar events could occur that would result in
damage, also of large proportion and reach, to the environment,
employees, contractors, communities and property. The
occurrence of any such events could have a material adverse
impact on the Group’s business, competitive position, cash
flow, results of operations, liquidity, future growth prospects,
shareholders’ returns and damage to the Group’s reputation.
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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 requirements and 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 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 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 those risks, environmental liabilities could be
substantial and could have a material adverse effect on Eni’s
results of operations, cash flow, financial condition, business
prospects, reputation and shareholders’ value, including
dividends and the share price.
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.
All these developments may adversely affect the Group’s
profitability, businesses outlook and reputation
Growing worldwide public concern over greenhouse gas
(GHG) emissions and climate change, as well as increasingly
regulations in this area, could adversely affect the Group’s
business and reputation, increase its operating costs and
reduce its results of operations, cash flow, financial condition,
business prospects and shareholders returns. 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 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 fuel over the medium to long-term, notably through the
diversification of the energy mix.
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 incentivize a
progressive shift in the energy mix away from fossil fuels,
for example, by subsidizing the power generation from
renewable sources.
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
FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIESEni Annual Report 2018 100
half of the GHG direct emissions coming from Eni operated
assets are already 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 expects that
governments require companies to apply technical measures to
reduce their GHG emissions. 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 (see note No.
27 to the Financial Statements). In 2018 to comply with
this carbon emissions scheme, Eni purchased on the open
market allowances corresponding to 12.7 million tonnes of
CO2 emissions. In certain jurisdictions, Eni is also subject to
carbon pricing schemes in Norway. 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 and could have a material adverse
effect on Eni’s operating costs and results of operations, cash
flow, financial condition, business prospects and shareholders’
returns. Eni also expects that governments will also 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 reduce
local demand for fossil fuels, 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 preserve energy
or use alternative energy sources, technological breakthrough
in the field of renewable energies or mass-adoption of electric
vehicles reduce the worldwide demand for oil and natural gas by
a large amount, Eni’s results of operations, cash flow, financial
condition, business prospects and shareholders’ returns 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 the entities responsible of the global warming
due to GHG emissions across the value chain and in particular
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. This trend could have a material
adverse effect on the price of our securities and our ability to
access equity or other capital markets. Additionally, the World
Bank has announced plans to stop financing upstream oil and
gas projects in 2019. Similarly, according to press reports, other
financial institutions also appear to be considering limiting their
exposure to certain fossil fuel projects. Accordingly, our ability
to use financing for future projects may be adversely impacted.
This could also adversely impact our potential partners’ ability
to finance their portion of costs, either through equity or debt.
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 results
of operations, cash flows, liquidity and business prospects.
For further information see pages 29-30 of the Annual Report
on Form 20-F 2018 - Item 4 - Information on the Company.
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 addition to existing provisions
accrued as of December 31, 2018 to account for ongoing
proceedings, in future years Eni may incur significant losses
in addition to the amounts already accrued in connection with
pending or future 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; (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 2018 consolidated
financial statements, 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
FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIES 101
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
materialize, expected synergies from acquisition may fall short
of management’s targets and Eni’s financial performance and
shareholders’ returns may be adversely affected.
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.
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, its business and operations
could be severely disrupted with negative consequences on
results of operations and cash flow.
Exposure to financial risk
Eni’s business activities are exposed to financial risk, which
includes exposure to market risk, including commodity price
risk, interest rate risk and foreign currency risk, as well as
liquidity risk, and credit risk.
Eni’s primary source of exposure to financial risk is the volatility
in commodity prices. Generally, the Group does not hedge its
strategic exposure to the commodity risk associated with its
plans to find and develop oil and gas reserves, volume of gas
purchased under its long-term gas purchase contracts, which
are not covered by contracted sales, its refining margins and
other activities. The Group’s risk management objectives in
addressing commodity risk are to optimize the risk profile of
its commercial activities by effectively managing economic
margins and safeguarding the value of Eni assets. To achieve
this, Eni engages in risk management activities seeking both to
hedge Group’s exposures and to profit from short-term market
opportunities and trading.
Eni is engaged in substantial trading and commercial activities
in the physical markets. Eni also uses financial instruments
such as futures, options, Over-the-Counter forward contracts,
market swaps and contracts for differences related to crude
oil, petroleum products, natural gas and electricity in order to
manage the commodity risk exposure. Eni also uses financial
instruments to manage foreign exchange and interest rate risk.
The Group’s approach to risk management includes identifying,
evaluating and managing the financial risk using a top-down
approach whereby the Board of Directors is responsible for
establishing the Group risk management strategy and setting
the maximum tolerable amounts of risk exposure. The Group’s
Chief Executive Officer is responsible for implementing the
Group risk management strategy, while the Group’s Chief
Financial Officer is in charge of defining policies and tools
to manage the Group’s exposure to financial risk, as well as
monitoring and reporting activities.
Various Group committees are in charge of defining internal
criteria, guidelines and targets of risk management activities
consistent with the strategy and limits defined at Eni’s top
level, to be used by the Group’s business units, including
monitoring and controlling activities. Although Eni believes it
has established sound risk management procedures, trading
activities involve elements of forecasting and Eni is exposed to
the risks of market movements, of incurring significant losses
if prices develop contrary to management expectations and of
default of counterparties.
Disruption to or breaches of Eni’s critical IT services or
information security systems could adversely affect the
Group’s activities
The Group’s activities depend heavily on the reliability and
security of its information technology (IT) systems. 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. 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.
FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIESEni Annual Report 2018
102
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, potentially having a
material adverse effect on the Group’s financial condition,
including its operating income and cash flow.
The United Kingdom leaving the European Union may affect
the Group’s results
On June 23, 2016, the UK held a referendum to decide on the
UK’s membership of the European Union. The UK vote was to
leave the European Union. There are a number of uncertainties
in connection with the future of the UK and its relationship
with the European Union. The negotiation of the UK’s exit terms
is likely to take a number of years. Until the terms and timing
of the UK’s exit from the European Union are clearer, it is not
possible to determine the impact that the referendum, the UK’s
departure from the European Union and/or any related matters
may have on the business of the Issuer.
As such, no assurance can be given that such matters would not
adversely affect the Company’s business prospects, results of
operations, cash flows and liquidity.
FINANCIAL REVIEW AND OTHER INFORMATION | RISK FACTORS AND UNCERTAINTIES OUTLOOK
103
For further information on Eni’s business outlook and financial and operational targets, please see the chapter “Scenario and Strategy”.
104
CONSOLIDATED DISCLOSURE
OF NON-FINANCIAL INFORMATION
In accordance with the Italian Legislative Decree 254/2016
Introduction
Eni’s 2018 Consolidated Disclosure of Non-Financial Information (NFI)
has been prepared by structuring the report on the three levers of
Eni’s integrated business model (Path to Decarbonisation, Operational
Excellence Model and Promotion of Local Development) whose
objective is to create long-term value for stakeholders, combining
financial stability with social and environmental sustainability.
The NFI provides an integrated view on the topics set out in Italian
Legislative Decree 254/2016, also by providing references to other
sections of the Annual Report or to the Corporate Governance Report,
if the information is already contained therein or to provide further
explanation. In particular, the Annual Report illustrates:
- Eni’s business and Governance Model;
- risk management in the sections (i) “Integrated Risk Management”,
including Eni’s Integrated Risk Management (IRM) model, the control
levels, the process – including the sustainability aspects – and its
governance, and the main activities for 2018; (ii) “Targets, risks and
treatment measures”, showing the Top Risks for Eni and the main
actions taken by the Company to mitigate them; (iii) “Risk factors
and uncertainties”, where the main non-financial risks, their potential
impacts and treatment actions 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”. Eni has
a regulatory system composed of direction, coordination and control
instruments (Policies and Management System Guidelines - MSGs)
and instruments which define the operating procedures (procedures
and operating instructions). The Policies, approved by the BoD,
define the principles and general rules of conduct on which Eni’s
activities must, without exception, be based. The MSGs, instead, are
common guidelines for all Eni units for the management of operating
and business support processes and cross-cutting compliance and
governance processes, including sustainability aspects;
- the main features of the “Eni Organizational and Management
Models” for the following issues: environment, climate, people,
health and safety, human rights, suppliers, transparency and anti-
corruption, local communities, innovation and digitalization;
- the strategy on the issues dealt with, the most significant
initiatives of the year and the main performance results with
related comments. The contents of the “Path to Decarbonization”
are drafted according to the voluntary recommendations of the
Task Force on Climate-related Financial Disclosures (TCFD) defined
by the Financial Stability Board.
Finally, reference to the main United Nations Sustainable Development
Goals (SDGs) has been included in the various chapters. The UN’s 2030
Agenda for Sustainable Development, presented in September 2015,
identifies 17 Sustainable Development Goals, which represent common
goals for the current complex social challenges. These goals are a
valuable source of guidance for the international community and for
Eni in conducting its activities in the Countries in which it operates.
As in previous years, Eni will also publish, on the occasion of the
Shareholders’ Meeting, the Sustainability Report (Eni For), which will
continue to be a voluntary disclosure document, certified according
to the GRI Standards and with its own limited assurance.
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 Corporate Governance Report.
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)
COMPANY MANAGEMENT
MODEL AND
GOVERNANCE
Art. 3.1, paragraph a)
• Eni’s organizational and management
models, p. 107
• Path to decarbonization, pp. 108-111
• Operational excellence model,
pp. 112-122
• Promotion of local development:
cooperation model, pp. 122-123
• Key sustainability topics, p. 124
AR
Business Model, p. 4
Responsible and sustainable approach, p. 5
Governance, pp. 24-29
Stakeholders engagement, pp. 14-15
CGR
Responsible and sustainable approach, pp. 8-10
Corporate Governance Model, pp. 11-13
Board of Directors: composition, pp. 35-40 and Board
POLICIES
Art. 3.1, paragraph b)
RISK MANAGEMENT
MODEL
Art. 3.1, paragraph c)
CGR
AR
• Main regulatory and guiding instruments
related to Legislative Decree 254/2016
topics, p. 106
• Path to decarbonization, pp. 108-111
• People, pp. 112-114
• Safety, p. 115
• Respect for the environment, pp. 116-118
• Human Rights, pp. 118-120
• Suppliers, p. 120
• Transparency and anti-corruption,
pp. 121-122
induction, p. 55
Board committees, pp. 55-64
Board of Statutory Auditors, pp. 64-73
Model 231, pp. 101-102
Eni Regulatory System, pp. 87-100
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. 87-102
105
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)
CLIMATE
CHANGE
Art. 3.2, paragraph a)
Art. 3.2, paragraph b)
• Main regulatory and guiding instruments related
to Legislative Decree 254/2016 topics, p. 106
• Eni’s organizational and management models,
p. 107
• Path to decarbonization (governance, risk
management, strategy and objectives),
pp. 108-111
AR Integrated Risk Management, pp. 20-23;
Safety, security, environmental and other
operational risks, pp. 89-91; Risks related
to climate change, pp. 99-100
Scenario and strategy, pp. 16-19
CGR Responsible and sustainable approach, pp. 8-10
O
T
H
T
A
P
I
I
N
O
T
A
Z
N
O
B
R
A
C
E
D
I
L
A
N
O
T
A
R
E
P
O
L
E
D
O
M
E
C
N
E
L
L
E
C
X
E
PEOPLE
Art. 3.2, paragraph d)
Art. 3.2, paragraph c)
• Main regulatory and guiding instruments related
to Legislative Decree 254/2016 topics, p. 106
• Eni’s organizational and management models,
p. 107
• People (employment, diversity and inclusion,
training, industrial relations, welfare, health),
pp. 112-114
• Safety, p. 115
AR Integrated Risk Management, pp. 20-23;
Risks associated with the exploration and
production of oil and natural gas, pp. 90-94;
Safety, security, environmental and other
operational risks, pp. 89-91
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, p. 106
• Eni’s organizational and management models,
p. 107
• Respect for the environment (circular economy,
water, spills, waste, biodiversity), pp. 116-118
AR Integrated Risk Management, pp. 20-23;
Risks associated with the exploration
and production of oil and natural gas,
pp. 91-94; Safety, security, environmental
and other operational risks, pp. 89-91
HUMAN RIGHTS
Art. 3.2, paragraph e)
• Main regulatory and guiding instruments related
to Legislative Decree 254/2016 topics, p. 106
• Eni’s organizational and management models,
p. 107
• Human rights (risk management, security,
training, whistleblowing), pp. 118-120
SUPPLIERS
Art. 3.1, paragraph c)
• Main regulatory and guiding instruments related
to Legislative Decree 254/2016 topics, p. 106
• Eni’s organizational and management models,
p. 107
• Suppliers (risk management), p. 120
CGR Responsible and sustainable approach, pp. 8-10
TRANSPARENCY
AND ANTI-
CORRUPTION
Art. 3.2, paragraph f)
• Main regulatory and guiding instruments related
to Legislative Decree 254/2016 topics, p. 106
• Eni’s organizational and management models,
AR Integrated Risk Management, pp. 20-23; Risks
related to legal proceedings and compliance with
anti-corruption legislation, p. 100
p. 107
The internal control and risk management
• Transparency and anti-corruption, pp. 121-122
system, p. 29
CGR Principles and values. Code of Ethics, p. 7;
Anti-Corruption Compliance Program, pp. 102-104
I
L
E
D
O
M
N
O
T
A
R
E
P
O
O
C
LOCAL
COMMUNITIES
Art. 3.2, paragraph d)
• Main regulatory and guiding instruments related
to Legislative Decree 254/2016 topics, p. 106
• Eni’s organizational and management models,
p. 107
• Promotion of local development: cooperation
model, pp. 122-123
AR Integrated Risk Management, pp. 20-23;
Political considerations, pp. 94-96;
Risks associated with the exploration and
production of oil and natural gas, pp. 91-94
:
T
N
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M
P
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E
V
E
D
L
A
C
O
L
F
O
N
O
T
O
M
O
R
P
I
Annual Report 2018.
AR
CGR Corporate Governance Report 2018.
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 2018
106
Main regulatory and guiding instruments related to Legislative Decree
254/2016 topics
PATH TO
DECARBONIZATION
CLIMATE
CHANGE
OBJECTIVE
Promote the energy transition
PUBLIC DOCUMENTS
“Sustainability” policy;
Eni’s Position on Biomass
PRINCIPLES:
• reduce greenhouse gas emissions, improving
plant efficiency and increasing the use of low
carbon content fuel
• develop and implement new technologies for
the reduction of Greenhouse gas emissions
and more efficient energy production
• use the opportunities offered by the
development of international carbon markets,
including tools to reduce deforestation
• promote sustainable management of water
resources
• assure a sustainable management of biomass
throughout the supply chain
• acquire palm oil produced only in a
sustainable way, in compliance with social,
environmental and safety requirements
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
PUBLIC DOCUMENTS
“Our people”, “Integrity in our operations”
policies
PRINCIPLES:
• respect the dignity of each person, valuing
diversity, whether related to culture, ethnicity,
gender, age, sexual orientation or disability
• provide managers with tools and support for
the management and development of the
people working for them
• identify the essential knowledge and skills
for Company growth and promote their
enhancement, development and sharing
• adopt equitable remuneration systems that
motivate and support the retention of the best
people to meet the needs of the business
• conduct activities in accordance with
agreements and regulations on workers’
health and safety and based on the principles
of precaution, prevention, protection and
continuous improvement
PUBLIC DOCUMENTS
“Sustainability”, “Integrity in our operations” policies;
“Eni biodiversity and ecosystem services policy”;
“Eni’s positioning with regards to Green Sourcing”
PRINCIPLES:
• consider, when evaluating projects and
in operational practices, the presence of
protected areas and of areas of biodiversity
value, identifying potential impacts and
mitigation actions
• ensure connections with environmental
aspects (climate, BES(a) and management of
water resources) and social issues such as the
sustainable development of local communities
• promote circular economy and the commitment
to the efficient use of resources
• promote Green Sourcing principles
• optimize control and reduction of emissions in
air, water and soil
• implement sustainable remediation to return
areas to the community or not use virgin areas
for new industrial initiatives
• carry out “risk based” environmental studies to
increase the quality of the response in the event
of accident
PROMOTION OF LOCAL
DEVELOPMENT:
COOPERATION MODEL
OPERATIONAL
EXCELLENCE MODEL
OPERATIONAL
EXCELLENCE MODEL
HUMAN
RIGHTS
OBJECTIVE
Protect human rights
PUBLIC DOCUMENTS
“Sustainability”, “Our people”, “Our Partners in the
Value Chain”, “Integrity in our operations” policies;
Code of Ethics; Eni Statement on Respect for Human
Rights
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 peoples 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
(a) Biodiversity and Ecosystem Services.
TRANSPARENCY AND
ANTI-CORRUPTION
LOCAL
COMMUNITIES
OBJECTIVE
Combat active and passive corruption
PUBLIC DOCUMENTS
“Anti-Corruption” Management System
Guideline; “Our partners in the value chain”
policy; Tax Strategy Guideline
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 the internal anti-corruption
regulations
OBJECTIVE
Promote relations with local communities and
contribute to their development
PUBLIC DOCUMENTS
“Sustainability” policy
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
• identify and assess the environmental,
social, economic and cultural impacts
generated by Eni activities, including those
on indigenous peoples
• promote free, prior and informed consultation
with local communities
• cooperate in initiatives to guarantee
independent, long-lasting and sustainable
local development
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION 107
DIMENSION
ORGANIZATIONAL AND MANAGEMENT MODELS
CLIMATE
CHANGE
• Organizational centralized function dedicated to Climate Change, Energy Efficiency & New Issues
• Long-term Positioning Initiatives Coordination Unit for Circular Economy and Carbon Neutrality initiatives in this area
• Climate Change Program cross-functional working group whose Steering Committee is chaired by the CEO: it aims to
gradually reduce GHG emissions in line with the 2 °C target
• 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 Solutions Department: business development for energy production from renewable sources and management of
relevant assets by dedicated companies
• Unit of the Legal Affairs Department dedicated to the topics of Climate Change, Sustainability and Circular Economy
• Energy management systems according to the ISO 50001 standard
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PEOPLE
SAFETY
• Employment management and planning process to align skills to the technical and professional needs of the Company
• Human resources management and development tools, aimed at professional growth and involvement,
inter-generational exchange of experiences, building of cross-cutting managerial development courses in line with the
Company’s strategic opportunities, professional development in core technical areas and valuing diversity
• 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 International Labour Organization 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
• Security management system aimed at ensuring protection for Eni people in all the Countries in which Eni operates and
particularly in high-risk Countries
• Welfare system for the achievement of work-life balance and the enhancement of services for employees and their families
• Integrated environmental, health and safety management system for workers with the aim of eliminating or mitigating the
risks to which workers are exposed during their work activities
• 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 environmental, 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 issues
• Green Sourcing: model to identify analysis methods and technical requirements to be adopted for the selection of products
and suppliers that are able to ensure better environmental performances
• 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
• Working Group on Business and Human Rights: to further align business processes with the main international standards
and best practices
HUMAN
RIGHTS
• 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)
• 231 Model: 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” department and reporting
directly to the Chief Executive Officer
• 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 the local level, who interfaces with the Company headquarters to define local community
development programs in line with national development plans integrating business processes
• Application of the ESHIA process to all 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
TRANSPARENCY
AND ANTI-
CORRUPTION
SUPPLIERS
LOCAL
COMMUNITIES
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• Centralized Research & Development Function for optimal sharing and best use 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
INNOVATION
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2018
108
PATH TO DECARBONIZATION
Taking into account the scientific evidence on climate change
of the Intergovernmental Panel on Climate Change (IPCC), Eni
intends to play a leading 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) published
in 2017. Disclosure on the path to decarbonization is structured
around the four topic areas covered by TCFD recommendations:
governance, risk management, strategy and metrics and
objectives. The key elements of each topic are presented below
and feature cross-references to the Eni for 2018 Report - Path to
Decarbonization1 for a complete analysis.
GOVERNANCE
Eni’s decarbonization strategy is part of a structured system
of Corporate Governance; within this, the Board of Directors
(BoD) and the Chief Executive Officer (CEO) play a central role
in managing the main aspects linked to climate change. The BoD
examines and approves, based on the CEO’s proposal, the Strategic
Plan, which sets out strategies and includes objectives also on
climate change and energy transition. Eni’s economic and financial
exposure to the risk that may derive from new carbon pricing
mechanisms is examined by the BoD both in the phase leading up
the authorisation of every investment and in the following half-year
monitoring of the entire project portfolio.
The BoD is also informed annually on the result 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 valued according
to the IEA SDS scenario (see pages 99-100). Finally, the BoD is
informed on a quarterly basis of the results of the risk assessment
and monitoring activities of Eni’s top risks, including climate change.
Since 2014, the BOD has been supported in conducting its duties
by the Sustainability and Scenarios Committee (CSS), with whom
examines, on a periodic basis, the integration between strategy,
future scenarios and the medium/long-term sustainability of the
business. During 2018, the CSS discussed in detail climate change
issues at all meetings, including the decarbonisation strategy,
energy scenarios, renewable energies, research and development
to support the energy transition, climate partnerships and water
resources and biodiversity issues2. Since the second half of 2017,
the BoD and the CEO are also supported by an Advisory Board,
composed of international experts, called to analyze the main
geopolitical, technological and economic trends, including issues
related to the decarbonization process3. In 2018, Eni also contributed
to the “Climate Governance”4 initiative of the World Economic Forum
(WEF), with the involvement of the Eni BoD. From 2015, the CEO also
chairs the Steering Committee of the Climate Change Program, a
cross-functional working group composed of members of Eni’s top
management that assists the CEO in developing and monitoring
an appropriate short/medium/long-term decarbonization strategy.
The strategic commitment to reduce greenhouse gas emissions is
part of the Company’s key goals. Therefore, the CEO’s short-term
incentive plan includes the objective of reducing the intensity of GHG
direct emissions from upstream operated activities by 12.5%. This
objective is consistent with the target of reducing greenhouse gases
by 2025 announced to the market and is applied to the incentives for
Company managers who have a strategic role on this matter. 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) as one of the founding companies. Established in
2014 by five European O&G companies, the OGCI now counts thirteen
companies, representing about one third of global hydrocarbon
production. In 2018, OGCI launched the first collective industry
target, undertaking to reduce the intensity of methane emissions
in upstream Oil & Gas operations. Through the Climate Investment
scheme, the OGCI is currently engaged in the joint investment of $1
billion over 10 years in the development of technologies to reduce
GHG emissions along the energy value chain at global level. As
regards partnerships, Eni is the only O&G company to be actively
involved, since the start of its work, in the Task Force on Climate
Related Financial Disclosure (TCFD), set-up by the Financial
Stability Board, which has drawn up voluntary recommendations for
corporate climate change disclosure. In keeping with its commitment
to climate disclosure, Eni has worked with its peers at the TCFD Oil &
Gas Preparer Forum to harmonize the needs of reporting companies
with those of users. In this context, the first status report on the
implementation of the recommendations in 2017 highlighted the
challenges of TCFD reporting and underscored the best practices: Eni
was brought forth as an example of how a company should publish
the risks and opportunities related to climate change in illustrating
its strategy. Transparency in climate change reporting and the
strategy implemented by the Company have allowed Eni to be, once
again in 2018, a leading company with an A- rating in the Climate
Change program of the CDP (formerly Carbon Disclosure Project), the
main independent rating that evaluates the actions and strategies of
listed international companies to combat climate change.
RISK MANAGEMENT
Eni has developed and adopted an Integrated Risk Management
(IRM) model to ensure that management takes risk-informed
decisions, taking fully into consideration current and potential
future risks, including medium and long-term ones, as part of an
organic and comprehensive vision.
The process is implemented using a “top-down, risk-based” approach,
starting from the contribution to the definition of Eni’s Strategic
Plan, by means of analyses that support the understanding and
(1) This report will be published on the occasion of the Shareholders’ Meeting scheduled in May.
(2) For more information, please refer to the section “Sustainability and Scenarios Committee” in the 2018 Corporate Governance Report.
(3) For more information, please refer to the chapter “Governance” of the Management report included in the Annual Report 2018.
(4) The initiative aims to raise the Boards’ level of awareness of climate-related issues, also following the recommendations of the Task Force on Climate-related Financial Disclosures (TCFD).
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION 109
evaluation of the likelihood of underlying risk (e.g. definition of
specific de-risking objectives) and continue with the support for
its implementation through periodic risk assessment & treatment
cycles and monitoring. Risk prioritization is carried out on the
basis of multi-dimensional matrices that measure the level of risk
by combining clusters of probability of occurrence and impact in
both quantitative and qualitative terms. 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
Climate change is analysed, evaluated and managed by
considering energy transition aspects (market scenario, regulatory
and technological evolution, reputational issues) and physical
phenomena. The analysis is carried out using an integrated and
cross-cutting approach which involves specialist departments and
business lines and considers the related risks and opportunities.
The main findings are shown below.
Market scenario. In the IEA Sustainable Development Scenario5
(WEO 2018), taken as a reference to assess the risks of the energy
transition, fossil fuels are expected to continue to play a central
role in the energy mix (Oil & Gas equal to 48% of the mix in 2040),
although in this scenario the global energy demand by 2040 is
expected to fall slightly. Natural gas, which grows also in the SDS
scenario, represents an opportunity for strategic repositioning for
energy companies, due to its lower carbon intensity, the possibility
of integration with renewable sources in electricity production and
the prospects of growing hydrogen production.
Oil demand is expected to grow in the other IEA scenarios (Current
Policies Scenario and New Policies Scenario), while in the IEA SDS
scenario a peak is expected in almost all Countries before 2030
(except India and sub-Saharan Africa). Nonetheless, also considering
the SDS scenario, there is 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 on the scenario, with a consequent impact on the Company
business model. Eni carries out an assessment of the potential costs
associated with GHG emissions, estimating them on the basis of the
Sustainable Development Scenario (SDS) of the International Energy
Agency (IEA), as illustrated more in detail in the section Risk Factors
and Uncertainty (see pages 99-100).
Regulatory developments. The adoption of policies designed
to support energy transition to low carbon sources could have
significant impacts on the business. The differentiated approach
by Country could provide an advantage for the development of new
business opportunities. With particular reference to the European
scenario, 2018 saw the entry into force of the amended EU-ETS
Directive (covering the 2021-2030 period), of the “Circular Economy
Package” and the approval of the Renewable Energy Directive (REDII,
in force from 2021). At the international level, in 2018 an agreement
was reached within the IMO (International Maritime Organization)
on the adoption of an initial strategy to reduce greenhouse
gas emissions from the shipping sector. Also in the light of this
regulatory development, Eni has strengthened its commitment to the
development of green business and renewable sources, as illustrated
more in detail in the section Strategy and Objectives.
Technological developments. The need to build a final energy
consumption model with low carbon footprint will favour technologies
aimed at capturing and reducing GHG emissions, the production of
hydrogen from gas as well as technologies that support the control
of methane emissions along the Oil & Gas production chain. These
elements will help to 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 in the efficiency of
electric vehicles could have impacts on the demand for hydrocarbons
and therefore on the business. Scientific and technological research
is therefore one of the levers on which Eni’s decarbonization strategy
is based and the areas of action are described in the section Strategy
and Objectives.
Reputation. The increasing attention being given to climate
change has an impact on the reputation of the entire Oil & Gas
industry, seen as one of the main parties responsible for GHG
emissions, with effects on the management of relations with the
key stakeholders. The ability to develop and implement strategies
to adapt the business model to a low carbon scenario, as well as the
capacity to communicate these in a transparent manner provides
an opportunity to improve stakeholder perceptions. As already
mentioned, Eni’s commitment to comprehensive and transparent
reporting on climate change issues is confirmed by its participation
in the TCFD proceedings and its recognition as a leading company
in the CDP Climate Change.
Physical risks. Increasingly intense extreme/chronic climate
phenomena in the medium to long term could cause damage
to plants and infrastructure, resulting in an interruption of
industrial activities and increased recovery and maintenance
costs. With regard 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 result
in 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 envision and implement
preventive mitigation measures to counter them.
STRATEGY AND OBJECTIVES
In relation to the risks and opportunities described above, Eni has
defined a clear decarbonization strategy, integrated in its business
model, that is developed in short/medium/long-term actions. Eni is
committed in the implementation of its scientific and technological
research activities (R&D) to achieve maximum efficiency in the
decarbonization process and find innovative solutions to facilitate
the energy transition.
In the short-term, Eni’s strategy is based on the following drivers:
- Efficiency increase and direct GHG emissions reduction of
operated activities: the objective for 2025 is to reduce upstream
emission intensity by 43% compared to 2014 by eliminating
process flaring, cutting fugitive methane emissions and
implementing energy efficiency measures. This objective will
contribute to the target of improving the operating efficiency
index by 2% a year by 2021 compared to 2014; it will be pursued
by all Eni business units through energy efficiency initiatives;
(5) International Energy Agency - Sustainable Development Scenario in the World Energy Outlook 2018.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2018 110
-
low carbon and resilient Oil & Gas portfolio: Eni’s hydrocarbon
portfolio has a high incidence of natural gas (>50%)6, a bridge to
a low-emission future. It is also characterized by conventional
projects developed in stages. The main upstream projects being
executed, which account for about 45% of the total development
investments in the sector in the 2019-2022 period, have a mean
portfolio breakeven point at a Brent price of $25 per barrel, and
are therefore resilient even in low carbon scenarios.
- development of renewables and green business: the promotion
of renewables aims at reaching an installed electricity generation
capacity equal to about 5 GW by 2025. In the green business
sector, stage two of the Venice bio-refinery is expected to be
completed by 2021, resulting in an increase in capacity to 560
ktons/year (360 ktons/year at present) and the start-up of
the Gela biorefinery, with a capacity of up to 720 ktons/year, is
scheduled in early 2019. The consolidation in Green Chemistry
is continuing and in 2018 it saw the acquisition of the organic
business of the Mossi & Ghisolfi Group and the development of
recycling and recovery projects.
In the medium term, Eni aims to achieve the net zero carbon
footprint on direct emissions of upstream activities valued (on an
equity basis) by 2030, maximizing decarbonization initiatives and
developing forestry projects to offset residual emissions.
An important role will also be played by the implementation of
solutions allowing the capture, storage and reuse of CO2. As a
further decarbonization driver, Eni intends to develop circular
economy initiatives aimed at enhancing waste and biomass to
extract new energy, new products or materials and to give new life
to decommissioned or reclaimed assets.
Overall spending in the four-year period 2019-22 for
decarbonization, the circular economy and renewables is
approximately €3.6 billion including scientific and technological
research activities designed to support these issues.
METRICS AND COMMENTS
As part of its decarbonization strategy, Eni has adopted indicators
that illustrate 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
renewables. With specific reference to emission rates, calculated
on data 100% of the operated asset for which Eni has set strategic
objectives, an overview of the results obtained in 2018 compared to
the set targets is provided below.
Reduction of the upstream GHG emission intensity index by 43%
by 2025 vs. 2014: the upstream GHG intensity index, expressed
as the ratio between direct emissions7 in tonnes of CO2eq and
thousands of barrels of oil equivalent, recorded a 6% decrease in
2018 compared to 2017, reaching 21.44 tCO2eq/kboe. This is a 20%
reduction compared to 2014, which is in line with the 2025 reduction
target. The improvement in the index in 2018 is mainly due to the
reduction in flaring emissions, the contribution to production of the
gas fields in Egypt (Zohr) and Indonesia (Jangkrik) and the return to
full operation in Norway (Goliat). Overall, these activities have a lower
emission intensity comapared to the portfolio average.
Zero process gas flaring by 2025: the volume of hydrocarbons sent
for process flaring in 2018 was equal to 1.4 billion Sm3, a decrease
of 9% compared to 2017 (1.6 billion Sm3), mainly as a result of
“zero flaring” achieved in Turkmenistan (Burun field). Through
the measures implemented, the volume of hydrocarbons sent for
process flaring was reduced by 16% compared to 2014, in line with
the goal of zero process flaring by 2025. In 2018, Eni invested €39
million in flaring-down projects, especially in Nigeria and Libya.
Reduction of upstream fugitive methane emissions by 80% by
2025 vs. 2014: in 2018, upstream fugitive methane emissions
were 38.8 kton CH4 (-66% vs. 2014) and were unchanged compared
to 2017 yet overall in line with the target. In this area, monitoring
and maintenance campaigns (Leak Detection And Repair - LDAR)
not only in the upstream sector, but also in the mid-downstream
sector (Sergaz), with a 6% reduction in total Eni fugitive methane
emissions compared to 2017.
Average improvement of 2% per year at 2021 compared to the
2014 operating efficiency index: the target extends the GHG
reduction objectives (scope 1 and scope 2) to all business areas
with the goal of improving the operating efficiency index by 2% a
year8. This objective refers to the overall Eni index, maintaining the
appropriate flexibility in the trends of the individual businesses.
In 2018, the index stood at 33.90 tonCO2eq/kboe, down 5.9% from
2017 (36.01 tonCO2eq/kboe). This reduction already makes it
possible to achieve the 2021 target, but Eni is nonetheless set on
pursuing an improvement of at least 2% per annum in coming years
as well. In addition to the upstream results already mentioned, this
reduction was also made possible by a reduction in the emission
intensity of refineries even with an increase in the performance
index of EniPower. In 2018, Eni invested about €10 million in energy
efficiency projects, which, once in full operation, will yield energy
savings of 313 ktoe/year, amounting to a reduction in emissions of
around 0.8 million tonnes of CO2eq.
In 2018, GHG direct emissions, calculated on all Eni activities,
amounted to 43.35 million tonCO2eq (figure for 100% operated
assets) and were stable (+0.5%) compared to 2017, while compared
to 2010 they decreased by 26%. Flaring emissions decreased by
8% compared to the previous year, also as a result of emergency
flaring containment measures, while venting emissions are in line
with 2017. In 2018, electricity produced from photovoltaic grew
by 20% YOY (19.3 vs. 16.1 GWh in 2017), while the production of
biofuels stood at 219 thousand tonnes, up 6% YOY. For 2018, Eni’s
economic investment in scientific research and technological
development amounted to €197.2 million, of which €74 million
was spent on investments regarding the Path of Decarbonization.
Energy transition, biorefining, green chemistry, renewable sources,
emissions’ reduction and energy efficiency were the main areas
targeted by these investments.
(6) Percentage of gas on total equity hydrocarbon resources 3P+ Contingent at 31/12/2018.
(7) The GHG emissions from methane venting have been revised following the refinement of the estimation methodology, in line with international methodologies developed thanks to
the CCMP OGMP Partnership. Therefore, the historical series of this emission category has been revised in order to ensure the consistency of the performance indices with respect to the
reduction targets of the GHGs communicated by Eni.
(8) It expresses the GHG emissions intensity (scope 1 and scope 2 calculated on an operatorship basis expressed in tonCO2eq and which consider the contributions of CO2, CH4 e N2O)
of Eni’s main industrial productions compared to operated production (converted by homogeneity into barrels of oil equivalent using the Eni average conversion factors published in the
Fact Book) in the individual businesses of reference, thus measuring their degree of operating efficiency in a decarbonization scenario. Scope 1 emissions are direct emissions from the
Company’s own assets. Scope 2 indirect emissions relate to the generation of electricity, steam and heat purchased from third parties.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION 111
2018
2017
2016
Operated
companies
Fully
Consolidated
entities
Operated
companies
Fully
Consolidated
entities
Operated
companies
Fully
Consolidated
entities
43.35
33.89
6.26
1.08
2.12
28.15
24.41
3.07
0.48
0.19
43.15
33.03
6.83
1.14
2.15
28.30
42.15
24.05
32.39
3.37
0.66
0.23
5.40
2.01
2.35
27.76
24.12
2.49
0.95
0.19
Key Performance Indicators
Direct GHG emissions (Scope 1)(a)
(million tonnes CO2eq)
of which: CO2eq from combustion and process
of which: CO2eq from flaring
of which: CO2eq from methane fugitive emissions
of which: CO2eq from venting
Carbon efficiency index
GHG emissions/100% operated hydrocarbon gross
production (UPS)
GHG emissions/Equivalent electricity produced (EniPower)
GHG emissions/Refinery throughputs
UPS methane fugitive emissions
Volumes of hydrocarbon sent to flaring
of which: sent to process flaring
Indirect GHG emissions (Scope 2)
Primary sources consumption(b)
Primary energy purchased from other companies
Electricity produced from photovoltaic(c)
Energy consumption from production activities/100%
operated hydrocarbon gross production (UPS)
Net consumption of primary resources / Electricity
produced (EniPower)
(tonnes CO2eq/kboe)
33.90
46.32
36.01
51.51
38.26
51.89
21.44
20.91
22.75
24.04
23.56
22.29
(gCO2eq/kWheq)
(tonnes CO2eq/kt)
(ktonnes CH4)
(billion Sm3)
(milllion tonnes CO2eq)
(Mtoe)
(GWh)
(GJ/toe)
402
253
38.8
1.9
1.4
0.67
13.0
0.4
19.3
1.42
407
253
15
1.1
0.6
0.56
9.4
0.4
19.2
n.a.
395
258
38.8
2.3
1.6
0.65
13.0
0.4
16.1
1.49
398
258
19.4
1.3
0.6
0.54
9.1
0.3
16.1
n.a.
398
278
72.6
1.9
1.5
0.71
12.5
0.4
13.5
1.71
(toe/MWheq)
0.17
0.17
0.16
0.16
0.16
Energy Intensity Index (refineries)
(%)
112.2
112.2
109.2
109.2
101.7
R&D expenditures
of which: related to decarbonization
First patent filing applications
of which: filed on renewable sources
Production of biofuels
Capacity of biorefinery
(€ million)
(number)
(ktonnes)
(ktonnes/year)
197.2
74
43
13
219
360
185
72
27
11
206
360
(a) The GHG emissions from methane venting have been revised following the refinement of the estimation methodology, in line with international methodologies developed thanks to
the CCMP OGMP Partnership. Therefore, the historical series of this emission category has been revised in order to ensure the consistency of the performance indices with respect to the
reduction targets of the GHGs communicated by Eni.
(b) The figure differs from the data of the last year as the reporting method was refined.
(c) Unlike the NFI 2017, where the data referred only to EniPower, the data shown relates to the entire Eni perimeter.
402
278
30.3
1.1
0.8
0.58
8.8
0.4
13.5
n.a.
0.16
101.7
161
63
40
12
181
360
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2018 112
OPERATIONAL EXCELLENCE MODEL
The operational excellence model lies in the constant commitment
to minimizing risks and creating opportunities along the whole
cycle of activities by enhancing people, safeguarding health
and safety, protecting the environment, ensuring respect for
and promoting human rights and paying the utmost attention to
transparency and the fight against corruption.
People
Eni’s business model is based on internal skills, an asset that
is built up over time and with dedication and which increases
its value in the long-term. In the coming years, Eni will continue
to be engaged in a crucial transformation process that will see
the development of new strategic guidelines – starting with the
circular economy and the activities supporting decarbonization –
alongside its traditional activities, which are currently in transition.
In doing so, it will seize all the opportunities offered by Digital
Transformation. Clearly, this will call for a continued effort to
develop internal skills in order to ensure that these are constantly
aligned with new business needs.
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 resource and a source
of value 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 that ensure
uniform management at a global level. With regard to gender
diversity, Eni pays particular attention to the choice of members
of the Boards of Directors of its subsidiaries, 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 area, Eni
takes part in national and international initiatives (Inspiring Girls
Project9, the “Manifesto for female employment”10 of Valore D,
Consorzio Elis – Sistema Scuola Impresa, WEF11 and ERT12) with the
aim of constantly enriching its processes and operating practices
to achieve gender parity. 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 (dual career),
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 development pathways, including the annual review and
the performance and feedback process with a focus on senior
managers, middle managers and young graduates. In 2018, 90% of
the target population was covered by the performance assessment
process and 95% by the annual review process.
Training. Training is given to Eni 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.
Training needs are mapped and evaluated annually according to
specific needs. With reference to the global scenario and the ongoing
digitalization process, the development and enhancement of digital
skills are among the top priorities; in November 2018, the “Digital
Transformation Center” platform was launched to make available
the new “digital” skills needed to develop and use innovative
technological solutions in operating processes. In addition, virtual
reality training is being tested to simulate dangerous situations in
controlled environments using the “learn-by-doing” approach. Finally,
Eni has provided for training courses available to all on strategic
issues, such as the Energy Transition and climate change.
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 in Eni) and a global one,
namely the Global Framework Agreement on International Industrial
Relations and Corporate Social Responsibility13. With regard to this
agreement, the second annual meeting was held on December 5,
2018 in Montreux. In addition to IndustriALL Global Union14, it was
attended by the main Italian trade unions, the members of the
Select Committee of the European Works Council15 and a delegation
of workers’ representatives from Eni’s businesses in Congo, Ghana,
Mozambique and Nigeria. During the meeting, Eni’s 2018-2021
Strategic Plan was presented, along with a focus on employment,
(9) International project against stereotypes of women.
(10) Program document aimed at enhancing female talent in the Company and promoted by Valore D with the patronage of the Italian presidency of the G7 and the Department for Equal
Opportunities of the Italian Presidency of the Council of Ministers.
(11) World Economic Forum.
(12) European Round Table.
(13) Second meeting since the signing of the Global Framework Agreement of July 7, 2016.
(14) Federation, founded in Copenhagen in 2012, representing more than 50 million workers in more than 140 Countries.
(15) The European Works Council is a body representing workers provided for by European Directive 94/45/EC to promote the transnational information and consultation of workers in undertakings.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION 113
the main HSE performance indicators and initiatives, Eni’s
sustainability approach and the activities of the Eni Foundation.
Parenthood, Welfare and Inclusion. Eni has continued with its
strategy of developing policies in favour of protecting parenthood
and the family, also in international mobility, by adopting in 2017, in
all the Countries in which Eni operates, concrete policies to support
maternity and paternity aimed at guaranteeing, in addition to the
international standards of the ILO Convention, a 10-day period of
fully paid leave for both parents. In 2018, the smart working pathway
for new parents continued and was opened to colleagues with
pathologies and in 2019, in Italy and depending on the positions held,
a further progressive extension of this work scheme will be assessed.
In 2018, Eni’s activities relating to services to people consolidated
and reinforced its initiatives in support of families, with particular
attention to services to employees who are caregivers of elderly
or non-self-sufficient people, as well as those aimed at promoting
health protection through the consolidation and extension of health
prevention programs. With regard to welfare in Italy, the Flexible
Benefit16 scheme has been in place at Eni since 2017 and in 2018 Eni
enhanced its supplementary health care offering to all non-managerial
employees, guaranteeing increased reimbursements and the
recognition of new reimbursable services as required in the “Welfare
Protocol” signed on July 4, 2017 with the relevant Trade Unions. At
the level of international labour law, a mapping of the ratifications of
the main ILO Conventions in the Countries where Eni is present was
carried out in 2018. This activity is further proof of the importance of,
and Eni’s commitment to, compliance with the fundamental principles
set out in the ILO Conventions and is aimed at analyzing the status of
ratifications in the Countries in which Eni operates.
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
in which it operates. The extreme variability of business 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 people and the communities in which
it operates. In 2018, 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
people and ensuring adequate risk management in the workplace.
METRICS AND COMMENTS
Overall employment amounts to 30,950 people, of whom 20,576
in Italy (66.5% of Eni employees) and 10,374 abroad (33.5% of Eni
employees). In 2018, employment at global level decreased by
1,245 people compared to 2017, equal to -3.9%, with an increase
in Italy (+108) and a reduction abroad (-1,353 employees) due
mainly to corporate reorganizations17.
Overall, in 2018, 1,728 hires were made, of which 1,264 with
permanent contracts. Of these, 29.1% covered female staff and
about 81% regarded employees under 40 years of age. Of the total
number of hires, approximately 42% were in the upstream business
area (total 361, of which 186 were with permanent contracts and
175 with fixed-term contracts), 25% in the R&M&C area and 33% in
the Gas & Power and Support Function areas. In all, 1,778 contracts
were terminated, 1,270 of which were permanent contracts18, and
25% regarded female employees. In 2018, 28.3% of the permanent
contracts terminated involved employees under the age of 40.
In 2018, the percentage of women in positions of responsibility rose to
25.28%, compared to 24.86% in 2017. Similarly, there was an upward
trend in the percentage of women on the management and control
bodies of Eni companies, reaching 33% and 39%, respectively, in 2018.
In Italy, 868 people were hired, 691 of whom with permanent
contracts (28.9% women, up 7% compared to 2017). The number
of personnel employed increased, particularly for the younger age
group (18-24), mainly due to the hires at industrial sites in Italy
including Viggiano, Livorno, Sannazzaro, Mantova and Taranto. In
2018, the number of terminations in Italy rose (+951 employees),
of which 640 permanent contracts (of which 21.7% were women).
In 2018, 860 hires were made abroad, of which 573 with permanent
contracts (of which 29.3% women) with 72.1% of employees
under the age of 40. Of the hires abroad, more than 60% refer to
the upstream business area (Mexico, Indonesia, Norway, and the
UK) and G&P business area (France, Hungary and the UK), with
the aim of developing and promoting new initiatives, as well as of
supporting turnover. As regards terminations, 827 contracts were
terminated, of which 630 permanent contracts. Of these, 43.3%
regarded employees under the age of 40, and 28.3% were women.
At year end, the balance between hires and terminations abroad
was +33 (+860 -827) and was basically the result of the growth of
the G&P retail business in France, the consolidation of R&M&C and
upstream activities in Mexico and Indonesia, the re-dimensioning
of activities in the gas business in Hungary and the release of
local and international employees in upstream activities in Nigeria,
Pakistan and the Americas. A reduction in local employees was
registered outside of Italy (-1,438 compared with the previous
year), resulting in a drop in the percentage of local staff out of total
employment abroad from 85.4% in 2017 to 82.6% in 2018. A total of
1,802 expatriates (of whom 1,261 are Italian) work abroad, slightly
up from 2017 (+27 Italians).
The average age of Eni people in the world is 45.4 years (46.7 in
Italy and 42.9 abroad; +0.1 years compared to 2017). The average
age is 49.3 years (50.3 in Italy and 46.9 abroad) for senior and
middle managers, 44.3 years (46 in Italy and 41 abroad) for white
collar workers, and 41.3 years (40.5 in Italy and 42.4 abroad) for
blue collar workers.
In 2018, thanks also to the “digital learning” initiatives delivered
through the “Digital Transformation Center”, there was a significant
5.2% increase in training hours compared to 2017.
In the field of health, the number of health services sustained19 by
Eni in 2018 was 473,437, of which 320,933 for employees, 66,327
for family members, 68,796 for contractors and 17,381 for others
(e.g., visitors and external patients).
The number of participants in health promotion initiatives19 in 2018
was 170,431, of whom 75,938 were employees, 46,930 contractors
and 47,563 family members.
(16) Initiative that enables a share of the performance bonus to be converted into goods and services, benefiting from the tax and contributions savings.
(17) Of note are the sale of Tigaz and the deconsolidation of Eni Norge.
(18) Of which about 50% for retirement and 40% for resignation.
(19) The health data consider the companies significant from the point of view of health impacts, with two points of view: the data only for the fully consolidated entities as required by the Decree
(data relating to occupational disease claims) and the data including companies under joint operation or joint control or associates in which Eni has control of operations (for all other data).
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2018 114
As concerns occupational illnesses, claims fell during 2018 from
120 to 81, with an overall reduction of 33%, due to the reduction
of illnesses reported, both by former employees (from 108 to 71
claims) and current employees (from 12 to 10 claims).
Of the 81 occupational disease claims submitted in 2018,
12 were submitted by heirs (11 relating to former employees
and 1 to an employee).
Key Performance Indicators
Employees as of December, 31st(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
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
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
2016
32,733
7,607
20,476
12,257
3,546
1,236
2,523
113
4,839
289
10,622
15,281
6,541
10,377
1,000
9,135
16,842
5,756
14,655
14,082
3,996
32,299
434
32,139
594
663
1,417
16.06
22.02
19.08
16.08
13.01
27
37
930,345
28.1
27.6
23.9
30.6
27.5
82.48
100
47.46
133
14
119
(%)
(years)
(%)
(number)
33
39
1,169,385
36.9
41.7
37.2
36.2
37.7
80.89
100
35.33
81
10
71
(%)
(number)
(a) The data differ from those published in the Annual Report (see inside cover) because they include only fully consolidated companies.
(b) The subdivision 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 (0.1% of total men).
(d) Outside of Italy, only the companies which a control body similar to the Italian Board of Statutory Auditors were considered.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION 115
developing and implementing a specific management system, in
line with international standards, and monitoring it with dedicated
audits. In terms of emergency preparedness and response, in
addition to continuous drills and monitoring of results, particular
attention is paid to the development of alert systems, the timeliness
of information communication via simplified flows and research on
natural risk scenarios which could interact with its business.
The Company’s main safety objectives concern: (i) the Safety
Culture Program (SCP), which monitors the level of proactivity
through preventive safety management aspects; (ii) the revision of
process safety standards in line with international best practices;
and (iii) the safety culture, with the launch of a new campaign for
office safety (“Safety starts @ office”).
In 2018, the Severity Incident Rate (SIR), an Eni weighted internal
index that measures the level of incident severity, was consolidated.
In particular, this indicator is used in the short-term incentive plan of
the CEO and senior managers with strategic responsibilities to focus
Eni’s commitment on reducing the most serious accidents.
METRICS AND COMMENTS
In 2018, the total recordable injuries rate (TRIR) of the workforce
increased by 6% compared to 2017. The worsening was determined
by the employees’ indicator (due to an increase in accidents), while
the contractors’ index remained stable. 4 fatal accidents occurred
to upstream contractors: 1 in Nigeria as a result of crushing by
a manoeuvring vehicle, 1 in Algeria as a result of burns, and 2 in
Egypt for falls from a height. The indicator for injuries at work with
serious consequences was affected by two events: one in Alaska
(upstream contractor who suffered a serious injury to his right leg)
and the other in Egypt (contractor who fell from a height).
In Italy, the number of total recordable accidents in 2018 increased
(40 events vs. 38 in 2017), but the total recordable injury rate
(TRIR) improved by 3%; however, the number of accidents abroad
increased (76 events vs. 63 in 2017) and the total recordable injury
rate worsened by 12%.
Safety
Eni believes that the safety of people is a fundamental value to be
shared among employees, contractors and local communities and
an essential part of its operations. For this purpose, Eni takes all the
necessary steps to eliminate the occurrence of accidents, including:
risk assessment and management organizational models, training
plans, skills development and promotion of a safety culture.
In 2018, to underscore the importance of maintaining correct and
safe behaviour not only in the workplace, the campaign “Safety
starts @ home” (aimed at employees) was launched through the
Company intranet, consisting of 10 video clips to promote safety at
home starting from the “Safety Golden Rules” (the 10 golden rules for
safety at work, mandatory at Eni from 2018) and the initiative “I live
safe” (for employees and third parties), a day dedicated to research
and the implementation of practical tools for building healthy and
safe habits even outside work through tangible and measurable
actions (with companies) to be adopted for the entire duration of
contracts. Meetings were also organised to raise workers’ awareness
of the lessons learned relating to accidents that occurred in the
Company, which in 2018 were mainly related to work at height and
the handling of loads. In particular, as regards the management of
contractors at Eni’s industrial sites, in 2018 control activities in the
field were further strengthened through the more than 120 members
of the Safety Competence Center20 assigned to the coordination and
supervision of the safety of work sites and contract works. More
than 2,300 companies, accounting for 70% of Eni’s HSE-critical
suppliers 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 Safety Competence
Center. Non-conformities found are immediately redressed with
corrective actions and good practices are recognized, shared and
disseminated. In 2018, the first trials of the application of the Safety
Competence Center’s operational methodologies were carried out
abroad (in particular in Tunisia and Angola), with positive results that
suggest a systematic implementation in the coming years.
Eni has also intensified its focus on process safety culture21,
Key Performance Indicators
Total Recordable Injury Rate (TRIR)
(total recordable injuries/hours worked)
x 1.000.000
Employees
Contractors
Number of fatalities as a result of work-
related injury
Employees
Contractors
(number)
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)
2018
2017
2016
Operated
companies
Fully
Consolidated
entities
Operated
companies
Fully
Consolidated
entities
Operated
companies
Fully
Consolidated
entities
0.35
0.37
0.34
4
0
4
0.01
0.00
0.01
1,431
330.6
91.6
239.0
0.41
0.42
0.41
1
0
1
0.01
0.00
0.01
1,128
190.9
57.5
133.4
0.33
0.30
0.34
1
0
1
0.00
0.01
0.00
1,550
306.3
93.1
213.3
0.45
0.44
0.46
0
0
0
0.01
0.02
0.00
1,223
174.2
59.4
114.8
0.35
0.36
0.35
2
0
2
0.01
0.01
0.01
1,643
276.9
93.7
183.2
0.38
0.41
0.36
1
0
1
0.01
0.02
0.01
1,270
168.9
61.4
107.5
(20) Eni Center of Excellence on Safety, which supports Eni’s industrial sites in Italy and abroad in the coordination and supervision of contract works.
(21) 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 2018
116
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.
The transition path towards a circular economy, in which
withdrawal of resources from the environment and waste disposal
are minimized, represents a challenge and an opportunity for Eni,
in terms of both profitability and improvement in environmental
performances. This path involves various areas: (i) update of
business models, producing renewable energy and/or using
recycled or renewable material in production activities (Energy
Solutions, Green Refinery and Green Chemistry); (ii) energy and
water efficiency programs in all sectors of the business, as well as
flaring down projects and projects to reduce methane losses with
resulting savings in natural gas; (iii) management of assets to be
decommissioned, through conversion, requalification, recovery and
sustainable reclamation projects; (iv) management tools, such as
green-c procurement and ICT solutions.
Eni promotes efficient water management, especially in water-
stressed areas, where in 2018 initiatives to reduce fresh water
withdrawals and projects in the upstream sector to give access
to water to populations in areas where Eni operates continued.
In Italy, Eni is committed to increasing, over the period of the
four-year plan, the amount of polluted groundwater treated 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 intensity of production. At the Centro Olio Val d’Agri (COVA),
a tender was launched to award a contract for the construction
of a Mini Blue water plant, based on proprietary technology, to be
installed with a treatment capacity of about 70 m3/h. Blue water
consists in an innovative process for the treatment of production
water, which leads to their reuse for industrial purposes.
Only a small proportion of Eni’s water withdrawals come from
freshwater sources (less than 7%). The analysis of river basin
stress levels22 and in-depth studies carried out at local level have
shown that freshwater samples from water-stressed areas account
for less than 2% of Eni’s total water withdrawals.
In water-stressed areas, Eni adopts specific water management
plans to reduce consumption. For example, at the Brindisi site, a
collaboration agreement was signed in 2018 between EniPower and
Syndial for the reuse of groundwater to reduce water withdrawals.
Considering the potential risks arising from possible water crises,
as noted by the annual survey conducted by the WEF23 and the
growing demand for information by stakeholders, for the first
time, in 2018, a public response was provided to the CDP water to
increase transparency on these issues.
Eni is committed every day to managing the risk of oil spills in
Italy and abroad through increasingly well-integrated actions in
all areas, from the administrative level to the technical areas of
prevention, control and quality/speed/effectiveness of intervention.
In 2018, the installation of the e-vpms® (Eni Vibroacustic Pipeline
Monitoring System) and SSPS (Safety Security Pipeline System)
tools for the detection of spills due to events, whether operational
or caused by sabotage, was completed on the Italian pipeline
network and on part of those in Nigeria.
To further increase preventive effectiveness, in 2019 an upgrade will
be installed on two pilot pipelines to detect activities in the vicinity
of the pipeline (excavations, vehicles, etc.) before a sabotage on
the pipeline. If the results are positive, it will be extended to all
finished product pipelines in Italy and gradually to other Company
realities. In 2018, a sabotage was detected in Egypt (JV Agiba),
which will be monitored based on the experience gained in Italy and
Nigeria, where intense monitoring activities continue through direct
surveillance, thanks also to the support of the local communities, the
use of aircraft and drones, as well as the installation of mechanical
protections. Finally, in terms of preparedness and response, the risk
analysis of the areas crossed by pipelines was completed in Italy,
identifying the most sensitive points at which to set up potential
containment actions in advance. At the same time, Eni will also work
on the experimentation/application of techniques for managing
impacts in the case of spills to improve the speed, quality and
effectiveness of intervention and surveillance.
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. Eni’s BES management
model is aligned with the strategic objectives of the Convention
on Biological Diversity (CBD) and ensures that the reciprocal
relationships between environmental and social aspects are
correctly identified and managed from the earliest project stages.
The biodiversity risk exposure of the global portfolio of the
upstream sector is periodically assessed by mapping the
geographical proximity to protected areas and areas important
for biodiversity conservation. This mapping allows identifying
priority sites where to take action with more detailed surveys to
characterize the operational and environmental context and assess
all potential impacts that are then mitigated through Action Plans,
thus ensuring effective management of risk exposure. Eni’s BES
management model is described in the BES Policy approved by the
CEO and published in 2018 on the Eni website24.
(22) 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.
(23) The Global Risks Landscape 2018 “What is the impact and likelihood of global risks?”.
(24) https://www.eni.com/docs/en_IT/enicom/sustainability/Eni-Biodiversity-and-Ecosystem-Services-Policy.pdf
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION 117
METRICS AND COMMENTS
In 2018, the downward trend (-2% vs. 2017) in freshwater
withdrawals continued, particularly thanks to the commissioning of
new steam generators at the Porto Marghera petrochemical plant to
replace steam/electric power generation units, with a reduction in
the amount of freshwater used in cooling cycles.
More than 75% of freshwater withdrawals are accounted for by
the R&M&C sector, while only 8% relate to the E&P sector. The
percentage on freshwater reuse has reached 87%.
In the E&P sector, production water re-injected has reached 60%,
mainly as a result of the good performance maintained by the
fields in Egypt and Ecuador.
The number of barrels spilled in operational oil spills has decreased
compared with 2017. Two major incidents were recorded, one at the
Livorno refinery (spillage from a tank caused by overfilling) and
the other at the Sarroch chemical plant in Sardinia (discovery of
soil with hydrocarbon product and water at a road crossing), both
with spills of about 500 barrels of product. The year 2018 saw a
reduction in the number of incidents by sabotage, while the volume
spilled increased by 14%; spills were related solely to the E&P
activities in Nigeria and Egypt. The barrels spilled in chemical spills
relate to upstream activities and Versalis.
Waste from production activities generated by Eni in 2018
increased compared to 2017, due in particular to the contribution
of non-hazardous waste (88% of the total), while hazardous
waste recorded a decrease. The increase is related to the E&P
sectors (in particular, due to the ramp-up of the Zohr project in
Egypt and the return to full operation of the Val d’Agri Oil Center,
which was also affected by the increased production of aquifer
water disposed of as waste) and R&M&C (following the general
shutdown of the Taranto refinery and the disposals following
flooding that occurred in 2017 at the Livorno refinery). The
amount of recovered/recycled waste has increased since 2017,
reaching almost 40% of total waste disposed25.
In 2018, a total of 4.3 million tonnes of waste was generated by
reclamation activities (of which 4 million tonnes by Syndial), of
which about 64% was groundwater. In 2018, €374 million was spent
on soil and groundwater reclamation.
The increase in SOX emissions compared to 2017 is due in
particular to the updating of the gas composition at some
upstream sites, thus resulting in an increased percentage of H2S
in the stream sent to the flare.
In 2018, biodiversity risk exposure was assessed on all
international and national concessions under development and/or
exploitation in the upstream sector26 (operated and joint ventures),
in order to identify those that affect (even partially) protected
areas27 and/or key biodiversity areas (KBAs)28.
A detailed analysis of these concessions, relating to the actual
position of the production sites within them (plants and/or
infrastructures), has shown that in 27 concessions, located in 6
Countries (United Kingdom, United States, Egypt29, Nigeria, Pakistan
and Italy), they are within one or more protected areas and/or
KBAs; while in another 31 concessions, located in 7 Countries
(United States, Ecuador, Tunisia, Congo, Nigeria, Pakistan and Italy),
the production sites are located outside, in areas adjacent to one or
more protected areas or KBAs.
Among the protected areas and/or KBAs that overlap with
production sites, 2 are included in the Ramsar List30, 3 are IUCN
protected areas31, 7 are other nationally designated protected
areas, 15 fall under the Natura 2000 classification, while 12 are
identified as KBAs. Of these areas, 26 are found in terrestrial
ecosystems, 11 in marine ecosystems and 2 in mixed ecosystems
(terrestrial and marine). No production site overlaps with World
Heritage sites (WHS32).
Instead, among the production sites located in areas adjacent to
protected areas or KBAs, only one is located near a WHS natural
heritage site (Mount Etna)33. The other areas concerned are: 2
are included in the Ramsar List, 18 are IUCN protected areas, 4
are other nationally designated protected areas, 35 fall under the
Natura 2000 classification, while 16 are identified as KBAs. Of
these sites, 67 are found in terrestrial ecosystems, 6 in marine
ecosystems and 3 in mixed ecosystems (terrestrial and marine).
(25) Specifically, in 2018, 16% of hazardous waste disposed of by Eni was recovered/recycled, 12% was subjected to chemical/physical treatment, 11% was incinerated, 3% was disposed of
in waste dumps and the remaining 58% was sent for other types of disposal (including transfer to temporary storage plants prior to final disposal). With regard to non-hazardous waste, 42%
was recovered/recycled, 1% was subjected to chemical/physical treatment, 0.3% was incinerated, 5% was disposed of in waste dumps and the remaining 51.7% was sent for other types of
disposal (including transfer to temporary storage plants prior to final disposal).
(26) Source: Company database, June 2018.
(27) Source: World Database of Protected Areas, December 2018.
(28) Source: World Database of Key Biodiversity Areas, June 2018. 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. To date, KBAs consist of two subsets: 1)
Important Bird and Biodiversity Areas; 2) Alliance for Zero Extinction Sites.
(29) In Egypt, 5 concessions have been assessed, of which only 1 belongs to fully consolidated entities as required by Italian Legislative Decree 254/2016; the remaining 4 are included in
the “operated” reporting perimeter.
(30) 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.
(31) IUCN, International Union for Conservation of Nature.
(32) WHS, World Heritage Site.
(33) Although the Zubair field (Iraq) is not included among the fully consolidated entities or within the “operated” reporting perimeter, it is located near the Ahwar site classified as a mixed
WHS site (natural and cultural). However, no operational infrastructure or activity falls within this protected area.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2018 118
Key Performance Indicators
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 spill
Total number of oil spills (> 1 barrel)
Volume of oil spill (> 1 barrel)(b)
Oil spills due to sabotage (including theft)
Total number of oil spills (> 1 barrel)
Volume of oil spill (> 1 barrel)
Chemical spill
Total number of oil spills
Volume of oil spill
2018
2017
2016
Operated
companies
Fully
Consolidated
entities
Operated
companies
Fully
Consolidated
entities
Operated
companies
Fully
Consolidated
entities
(Mm3)
1,776
1,731
1,786
1,640
1,626
1,650
104
119
72
17
5
4
7
1
88
49
34
79
20
10
4
6
16
86
59
55
1,746
1,638
106
70
17
9
4
6
1
87
45
24
1,851
1,710
129
87
23
9
3
7
12
84
58
85
1,816
1,697
117
78
20
9
3
7
2
85
42
44
724
2,217
3,323
3,049
1,231
94
102
102
158
3,277
3,236
3,236
4,682
158
4,682
34
61
1.3
0.2
1.1
31.6
6.2
13.8
0.8
17
63
1.4
0.7
0.7
55.6
8.4
21.5
1.5
15
50
0.8
0.3
0.5
30.8
6.7
13.4
0.7
24
18
0.8
0.3
0.5
56
8.9
15.9
1.4
24
18
0.6
0.2
0.4
32.1
5.5
9.2
0.7
117
81
19
6
4
7
19
87
60
72
2,665
97
3,697
34
61
2.6
0.3
2.3
53.1
16.5
23.1
1.5
(%)
(number)
(barrels)
(number)
(barrels)
(number)
(barrels)
Total waste from production activities
(million tonnes)
of which hazardous waste
of which non-hazardous waste
NOX (nitrogen oxides) emissions
SOX (sulphur oxides) emissions
NMVOC (Non Methane Volatile Organic Compounds) emissions
(ktonnes NO2eq)
(ktonnes SO2eq)
(ktonnes)
TSP (Total Suspended Particulate) emissions
(a) TAF: Groundwater treatment.
(b) The 2017 figure was updated following the closure of some investigations after the publication of the 2017 NFI. This circumstance could also occur for the 2018 data.
Human Rights
Eni is committed to respecting international human rights
standards, starting with the UN’s Guiding Principles on Business
and Human Rights, with the aim of continuously improving its due
diligence system. Human rights is one of the areas in which the Eni
Sustainability and Scenarios Committee (CSS) performs consultative
and advisory functions for the BoD. In 2018, the CSS examined
numerous aspects that directly or indirectly concern human rights,
including the analysis of the results achieved by Eni in the second
edition of the Corporate Human Rights Benchmark (CHRB)34 and
the draft of Eni’s Statement on Respect for Human Rights, approved
by the BoD in December 2018 and drawn up with the support of the
inter-functional working group on “Human Rights and Business”35.
This Statement strengthens the corporate commitment previously
expressed on the subject, aligning it with the main international
standards on human rights and business, starting with the United
Nations Guiding Principles, and also highlighting the priority areas on
which this commitment is focused.
During 2018, the activities of the working group continued, making
it possible to identify the main areas for improvement and the
actions necessary for the continuous improvement of performance.
These actions have been incorporated into a specific multi-year
plan that has been broken down into managerial objectives linked
(34) Eni ranked first among the energy companies and seventh among all 101 companies in the different sectors analysed.
(35) Created in 2017 following an event chaired by the CEO addressed to the members of the BoD, Board of Statutory Auditors and Management on the issue of Business and Human Rights.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION
119
to human rights performance. In 2018, therefore, 8 out of 16
managers reporting to the CEO were assigned a target directly
related to human rights.
The subject of respect for human rights is integrated at various
levels in Company processes and Eni monitors the risk of
possible abuses with specific instruments such as, for example,
the Integrated Risk Management (IRM) model, in which these
issues are considered in the risk model and integrated in the
risk assessment in the social, environmental, health, safety and
reputation impact metrics.
Following the internal awareness-raising process on human rights
launched in 2016, in 2018, human rights training at Eni saw the
delivery of specific e-learning courses for some functions, which
expanded on the course provided in 2016-2017 to all employees.
These courses, developed with the support of the Danish Institute for
Human Rights, are aimed at creating a language and a common and
shared culture about human rights and at improving understanding
of the possible impacts of business on human rights.
In 2017, Eni identified 4 areas involving the human rights
considered most relevant to the activities carried out directly and
those carried out by its business partners, the so-called “Salient
Issues”. During 2018, these areas were shared with external
stakeholders and authoritative experts: human rights (i) in the
workplace36; (ii) in the supply chain; (iii) in communities; and (iv)
in security operations.
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 2018, 20 suppliers were assessed, including 1 from
Ecuador, 2 from Vietnam, 2 from Egypt and 15 from Italy. Eni is
also committed to drawing up a code of conduct for suppliers37,
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 Modern Slavery
Statement38 and in the Position Statement on “Conflict minerals”39.
Eni is committed to preventing possible negative impacts on the
human rights of individuals and host communities by providing
for appropriate management measures. For this purpose, in 2018,
Human Rights Impact Assessments (HRIA) were carried out in
Mozambique and Angola, in addition to the follow-up to the one
carried out in Myanmar in 2016, for which Eni availed itself of the
support of the Danish Institute for Human Rights. A model was
also developed for classifying business projects to determine the
associated level of risk of social impact and the impact on human
rights, based on which appropriate in-depth studies are undertaken,
including the HRIAs.
Eni manages its security operations in accordance with
international principles, including the Voluntary Principles on
Security & Human Rights. Eni has designed a coherent set of rules,
processes and tools to ensure that: (i) the suppliers of security
forces are selected according to human rights criteria; (ii) the
contractual terms include provisions on the respect of human
rights; (iii) security operators and supervisors receive adequate
training; and (iv) the events considered most at risk are managed
in accordance with international standards.
As a complement to all the actions taken to ensure respect for human
rights, since 2006 an Eni procedure has been in place, included in the
Anti-Corruption Regulatory Instruments, which regulates the process
of receiving, analysing and handling any whistleblowing reports,
even anonymously, from employees or third parties.
METRICS AND COMMENTS
In 2018, the human rights training programme continued (after
the massive campaign between 2016 and 2017) with specific
follow-up initiatives for thematic insights that will continue in 2019
together with the campaign for the procurement professional area.
In addition, the “Sustainability and Business Integration” course in
English and French was made available to all Eni employees, for a
total of approximately 7,100 enrollments.
In 2018, e-learning courses dealt with human rights and
specifically: relations with local communities (140 people),
workplace (about 1,740 people) and security (207 people),
aimed at different employee targets depending on the content of
the training modules. Human rights & security are also regularly
addressed in all training courses for security personnel, such as
workshops for newly appointed Security Managers and Security
Officers, and generic and specific e-learning training. Thanks also
to the courses mentioned above, the staff belonging to the Security
professional area trained in human rights reached 96%.
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 2018, the training session was held in Tunis and
was addressed to private security operators who work at Eni’s
management and operational sites.
With regard to whistleblowing reports, in 2018 investigations were
completed on 79 files, 3140 of which included human rights aspects,
mainly concerning potential impacts on workers’ rights. Among these,
34 assertions were checked: the events reported were confirmed, at
least in part, for only 9 of these, and actions were taken to mitigate
and/or minimize the impacts including: (i) actions on the Internal
Control and Risk Management System, relating to the implementation
and strengthening of controls in place, and awareness-raising 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, 21 files were
still open, 5 of which referred to human rights aspects, in particular
potential impacts on workers’ rights.
(36) Please refer to the section “People” on pages 112-114.
(37) In 2018, a draft of the document was drawn up and a pilot campaign was launched, in Italy and abroad, which ended with a good response from suppliers.
(38) In accordance with the UK Modern Slavery Act 2015.
(39) In accordance with US SEC regulations.
(40) All relating to companies consolidated on a line-by-line basis.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2018 120
Key Performance Indicators
Hours of training on human rights
In class
Distance
Employees trained on human rights(a)
Security personnel trained on human rights
Security personnel (professional area) trained on human rights(c)
Security contracts containing clauses on human rights
Whistleblowing reports(d) (assertions)(e) on human rights violations closed during the
year(f), of which:
Founded reports (assertions)
Unfounded reports (assertions), with the adoption of corrective/improvement measures
Unfounded/generic reports (assertions)
(number)
(%)
(number)
(%)
2018
10,653
164
10,489
91
73
96
90
2017
7,805
52
7,753
74
308(b)
88
88
(number)
31 (34)
29 (32)
9
9
16
3
9
20
2016
88,874
354
88,520
-
53
83
91
36
11
6
19
(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 resources trained on human rights, in some cases also significant, which can be detected 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 value cumulated.
(d) Whistleblowing report: it is a summary document of the investigations carried out on the whistleblowing report(s) (which may contain one or more detailed and verifiable assertions)
including the summary of the investigation carried out, the results of such investigation and any identified action plan.
(e) 2016 data refers to the whistleblowing reports (and not to the assertions).
(f) 2016 and 2017 data include some cases related to not fully consolidated entities:
- 2016: 1 unfounded report with the adoption of improvement measures;
- 2017: 1 report with 1 unfounded/generic assertion.
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 rights, 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 2018, more than 5,000 suppliers (including all the new
ones) were subject to checks and assessment with reference to
environmental and social sustainability aspects (i.e. health, safety,
environment, human rights, anti-corruption and compliance). For
19% of these suppliers, potential criticalities and/or possible areas for
improvement were identified; in 91% of cases these were not serious
enough to compromise the possibility of working with them, while for
the remaining 9% of suppliers checked, the criticalities revealed led to
the temporary suspension of relations with Eni. In 2018 criticalities
and/or areas for improvement were in fact identified on 1,008
suppliers; for 95 of these the assessment at the qualification stage
was negative (i.e. non qualified) or Eni issued preventive measures
(monitoring, state of attention with clearance, suspension or
revocation of qualification); the 2018 figure for supplier suspensions,
which shows a drop compared to previous years, reflects the reduced
number of investigations for unlawful conduct involving Eni suppliers
in the year. 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
(%)
2018
5,184
1,008
95
100%
2017
5,055
1,248
65
100%
2016
5,171
1,336
131
100%
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION
121
Transparency and anti-corruption
Eni takes part in the Global Compact (GC), 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 United Nations’ Sustainable
Development Goals (SDGs).
The GC principles are reflected in Eni’s Code of Ethics. In particular,
the repudiation of all forms of corruption has been one of the
fundamental ethical principles of Eni’s Code of Ethics since 1998
– shared among all employees when recruited – and the 231
Model. Eni has also designed and developed the Anti-Corruption
Compliance Program, in accordance with the applicable rules
in force, the international conventions and taking into account
relevant guidance and best practices, as well as the policies
adopted by the main international organisations. It is an organic
system of rules and controls to prevent corruption practices.
All Eni’s subsidiaries, in Italy and abroad, are required to adopt,
by resolution of their own BoD41, both the Management System
Guideline42 and all the other anti-corruption regulatory instruments
issued by the parent company.
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. At December 31, 2018, Eni was subject to two
surveillance audits, both successfully concluded.
To guarantee the effectiveness of Eni’s Anti-Corruption Compliance
Program, in 2010 an ad hoc organizational structure was formed,
the anti-corruption unit, which is responsible for providing
specialist support to business lines and subsidiaries in Italy and
abroad. This unit also implements an anti-corruption training
program, both through e-learning and with classroom events,
general workshops and job specific training. The workshops,
designed using interactive formats, are carried out on the basis
of the index produced annually by Transparency International
(Corruption Perception Index) and of Eni’s presence in each
Country. These workshops offer an overview of the anticorruption
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
2018, a methodology was developed to systematically group Eni’s
people for the risk of corruption on the basis of risk drivers such as:
Country, position, professional area and number of employees of
the site, in order to optimize the identification of the target audience
of the various training initiatives. The methodology is expected
to be rolled out in 2019. In addition, in 2018 a communication
initiative on the Company’s intranet called “Compliance Tips”
was implemented to promote the dissemination of the culture of
compliance at all levels; it addressed possible situations at risk that
an employee might face.
In addition, 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.
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 required contractually.
As evidence of Eni’s commitment to improve governance and
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)43.
Membership in the EITI is a value for Eni despite the fact that
since 2017 the Company has published the “Report on payments
to governments” in accordance with the reporting obligations
introduced by the European Directive 2013/34 EU (Accounting
Directive). Furthermore, on May 24, 2018, the BoD approved the Tax
Strategy Guidelines, which set out Eni’s commitments in terms of tax
transparency, aimed at paying taxes in the various Countries where
value is generated in a manner consistent with the letter and spirit of
the laws in force, in line with OECD recommendations on combating
tax evasion and shifting profits towards Countries with low taxation
(Base Erosion and Profit Shifting) by Multinational Enterprises.
METRICS AND COMMENTS
During 2018, 32 audits were carried out in 13 Countries, with
anti-corruption checks that confirmed the overall adequacy and
effective operation of the Anti-Corruption Compliance Program.
In 2018, the anti-corruption e-learning campaign aimed at training
the entire Company population continued; these campaigns are
gradually being completed, thus ensuring full coverage in terms of
training for all Eni people. In 2018, this campaign reached 2,844
employees, 32% of whom were managers, with a coverage that
reflects Eni’s presence in the Countries in which it operates: 41% in
Italy, 29% in Africa, 17% in Asia, 11% in the rest of Europe and 2% in
the Americas.
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, it participates in the activities
of the Multi Stakeholder Group in Congo, Mozambique, East Timor,
Ghana, and the UK. In Kazakhstan, Nigeria and Mexico, Eni’s
subsidiaries interface with EITI’s local Multi Stakeholder Groups
through trade associations in the Countries.
(41) Or alternatively the equivalent body depending on the governance of the subsidiary.
(42) 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.
(43) Global initiative to promote responsible and transparent use of the financial resources generated in the extraction sector.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2018 122
Key Performance Indicators
2018
2017
2016
Audit actions on risk of corruption activities
(number)
32
(number of participants)
951
920
493
E-learning for managers
E-learning for other resources
General Workshop
Job specific training
Fully
Consolidated
entities
Total
Fully
Consolidated
entities
Total
Fully
Consolidated
entities
33
822
Total
865
36
452
1,950
1,765
1,461
1,924
1,857
1,736
9,364
8,952
1,765
1,434
1,329
1,269(a)
1,461
1,539
1,503
1,214(a)
Countries where Eni supports EITI’s local Multi Stakeholder Groups
(number)
8
9
8
(a) The figure includes a small number of Eni resources belonging to companies not included in the scope of consolidation with the integral method which cannot be separated from the
consolidated data.
PROMOTION OF
LOCAL DEVELOPMENT:
COOPERATION MODEL
Eni’s distinctive mark has always been its willingness to meet
the development needs of the Countries in which it operates,
collaborating on a regular basis with local authorities and
stakeholders. For this to happen, Eni has adopted a systematic
and applicable approach at all stages of the business in all
operating contexts. In recent years Eni has ensured that from
the negotiation phase, through exploration, to all operational
processes, including decommissioning, there are adequate
tools to know the local socio-economic context, also in relation
to human rights, and to manage the demands of stakeholders
as well as the needs of communities. These tools allow defining
a structured intervention plan at local level that ensures the
integration of both local needs and the guidelines contained in
national development plans, in the United Nations 2030 Agenda
and in the National Determined Contributions (NDCs).
The support for local development strategy is centered on people
and is based on enhancement of the energy resources of the
Countries and the definition of initiatives to improve the living
conditions of local communities. The development of energy
sources is the target of Eni’s business model and involves the
construction of infrastructure for the production and transport of
gas for both export and local consumption, and the construction of
off-grid and on-grid electricity production plants.
Supporting development tailored to local needs, in line with
business objectives in a long-term perspective and minimising
socio-economic gaps by involving all stakeholders means today
to tackle increasingly complex and global events such as climate
change and migratory phenomena that require extending the scope
of action beyond the “operating area” of plants.
In order to address these current and future challenges, Eni’s
cooperation model has three directions:
1. Community investment: Eni promotes a wide range of
initiatives to improve people’s living conditions through economic
diversification initiatives such as the development of agricultural
projects, micro-enterprise, micro-credit or infrastructure projects,
and education, water access and through health protection, such as
the strengthening of public health services and awareness-raising
and empowerment activities of the beneficiary populations.
2. Public Private Partnership: in keeping with the 2015 Addis
Ababa agreement “Financing for development”, Eni has started
collaborations with development cooperation organizations to pool
resources not only in economic terms but also in terms of skills,
know-how and experience. Specifically, in 2018 Eni established
public-private partnerships with the United Nations Development
Programme (UNDP) to contribute to sustainable development
and promote the achievement of the SDGs, in particular universal
access to energy by 2030, actions to combat climate change
and the protection, restoration and sustainable use of the earth’s
ecosystem and with the Food and Agricultural Organization (FAO)
for access to clean and safe water in Nigeria.
3. Monitoring and evaluation of the direct, indirect and induced
effects of Eni’s presence at local level: to measure the impacts
and benefits of its initiatives and amplify their effects, in
collaboration with the Polytechnic of Milan, Eni has developed two
tools: the ELCE (Eni Local Content Evaluation) Model and the Eni
Impact Tool44.
(44) 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.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION 123
Another tool for relations with local communities is the Stakeholder
Management System for mapping, managing and monitoring
relations with its stakeholders in the Countries where it operates
and managing grievances at all stages of the business to ensure
that all stakeholder suggestions are taken into account, to provide
adequate responses and to prevent potential risk factors. As of
2018, this mapping also includes indigenous peoples located close
by the operations and operated projects.
Monitoring activities also include analyses to measure the
percentage spent on local suppliers at some major upstream
foreign subsidiaries. The 2018 percentage spent on local suppliers
in these Countries is about 33%.
METRICS AND COMMENTS
In 2018, overall spending on community investment amounted
to about €94.8 million (Eni share), of which approximately 98%
related to upstream activities. In Asia, approximately €21.9 million
was spent, mainly on economic diversification, in particular for
the maintenance of road infrastructure (bridges and roads). In
Africa a total of €46.7 million was spent, of which €43.9 million
was on Sub-Saharan Africa, mainly in the area of professional
training and the construction of school infrastructure (net of
expenditure on resettlement). About €32.4 million was invested
in infrastructure development, of which €13.4 million was in
Africa and €15.2 million in Asia. In the field of health, in 2018,
in order to assess the potential impact of projects on the health
of the communities involved, the upstream sector completed
20 studies (Health Impact Assessment), of which 7 were
integrated ESHIA studies (Environmental, Social and Health
Impact Assessment). In addition, 3 HRIA (Human Rights Impact
Assessment45), studies were carried out. The total number
of grievances received is 193, of which 138 cases have been
resolved and closed. In particular, 97% of complaints in Ghana
were closed.
Key Performance Indicators
Community investment(a)
of which: infrastructure
(€ million)
2018
2017
2016
Fully
Consolidated
entities
73.9
29.6
Total
94.8
32.4
Fully
Consolidated
entities
66.8
22.1
Total
70.7
22.1
Fully
Consolidated
entities
60.3
23.3
Total
64.2
23.3
(a) The data includes resettlement activities: amounting to € 19.1 million in 2018.
(45) See the section “Human Rights” on pages 118-120 for more information.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2018 124
KEY SUSTAINABILITY TOPICS
For Eni, key sustainability topics are those priority aspects for
the Company and its stakeholders that identify the challenges
and key opportunities of the entire value creation cycle in the
long term.
Process for determining key topics
For Eni, determining key sustainability topics is based on a process of identifying issues and setting priorities. It takes into account:
1
2
ANALYSIS OF THE
SCENARIO
Topics emerging from the business
environment and progress with respect to
the Strategic Plan. The analysis is presented
every year at the Sustainability and Scenarios
Committee and approved by the Eni BoD.
RISK ASSESSMENT
RESULTS
Main risks including potential
environmental, social, reputational and
health and safety impacts.
These are submitted to the BoD on a
quarterly basis by the CEO.
3
STAKEHOLDERS’
PERSPECTIVE
Key sustainability topics
according to Eni’s various
stakeholders46.
The identified topics, according to the priorities set for the different
business lines, are the basis for the elaboration of the four-year
Strategic Plan and the non-financial reporting (Consolidated
Disclosure of Non-Financial Information and Eni for). Then, the
sustainability management objectives (MBOs) assigned to all
managers are determined based on the Strategic Plan. The key
topics are then presented to the Management Committee and
Sustainability and Scenarios Committee, and reported to the BoD at
the beginning of the reporting process.
Below are the 2018 key topics associated with the sustainable
development goals (SDGs) on which Eni’s activities have a direct or
indirect impact.
2018 KEY TOPICS
PATH TO DECARBONIZATION
COMBATING CLIMATE
CHANGE
TECHNOLOGICAL INNOVATION
OPERATIONAL EXCELLENCE MODEL
PEOPLE
SAFETY
GHG emissions, promotion of natural gas,
renewables, biofuels and green chemistry
SDGs: 7 - 9 - 12 - 13 - 17
SDGs: 7 - 9 - 12 - 13 - 17
Employment and Diversity and Inclusion
Training
Occupational health and local communities health
SDGs: 3 - 4 - 5 - 8
People safety and asset integrity
SDGs: 3 - 8 - 11
REDUCTION OF ENVIRONMENTAL IMPACTS Water resources, biodiversity and oil spills
SDGs: 3 - 6 - 12 - 14 - 15
HUMAN RIGHTS
Rights of workers and local communities,
Supply chain and Security
SDGs: 4 - 8 - 10 - 16 - 17
INTEGRITY IN BUSINESS MANAGEMENT
Transparency and Anti-Corruption
SDGs: 10 - 16 - 17
PROMOTION OF LOCAL DEVELOPMENT: COOPERATION MODEL
ACCESS TO ENERGY
LOCAL DEVELOPMENT THROUGH
PUBLIC-PRIVATE PARTNERSHIPS
Economic diversification, Education
and Training, Access to water
and hygiene, Health
SDGs: 7 - 9 - 10 - 17
SDGs: 2 - 3 - 4 - 6 - 8 - 10 - 17
LOCAL CONTENT
SDGs: 4 - 8 - 9
(46) Identified according to GRI standards, AA1000 Accountability and International Finance Corporation guidelines.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION 125
REPORTING PRINCIPLES AND CRITERIA
The Consolidated Disclosure of Non-Financial Information is drafted
in accordance with the Decree 254/2016 and with the “Sustainability
Reporting Standards”, published by the Global Reporting Initiative
(GRI Standards), which represent the reporting standard adopted.
The document is drafted in accordance with the “core” option of
the GRI Standards and had undergone a limited assurance by the
independent company which provided assurance to Eni Group’s
Annual Report as of December 31, 2018. All figures refer to Eni SpA
and its fully consolidated entities. In addition, an additional view
was added in line with other corporate documents and in continuity
with the past for data concerning safety, environment, climate,
whistleblowing reports, anti-corruption training and community
investment. The safety, environment and climate data consider the
companies significant from the point of view of HSE impacts, with
two points of view: the data only for the fully consolidated entities as
required by the Decree and the data including companies under joint
operation or joint control or associates in which Eni has control of
operations47. In addition to providing continuity with respect to past
publications and consistency with the objectives that the Company
has set itself, the aim is to represent the potential impacts of the
activities managed by Eni. Comments on safety, environment and
climate data refer to the perimeter including the companies over
which Eni has control of operations. Key Performance Indicators,
selected according to items identified as the most relevant,
are collected on an annual basis according to the consolidation
perimeter of the relevant year and relate to the 2016-2018 period.
All GRI indicators in the Content Index refer to the version of the GRI
Standards published in 2016, with the exception of those of the
Standards 403: occupational health and safety, which refer to the
2018 edition.
KPI
METHODOLOGY
CLIMATE CHANGE
GHG
EMISSIONS
EMISSION
INTENSITY
Scope 1: the GHGs include CO2, CH4 and N2O emissions; the Global Warming Potential used is 25 for CH4 and 298 for N2O. In 2019, the
Eni inventory will be certified in accordance with ISAE3000/3410. The emission factors used for the calculations are, where possible,
site specific or, as an alternative, drawn from the international documents available.
Scope 2: Scope 2 indirect emissions relate to the generation of electricity, steam and heat purchased from third parties and include
the contributions of CO2, CH4 and N2O.
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
OPERATIONAL
EFFICIENCY
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.
ENERGY
CONSUMPTION
Consumption from primary sources: 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.
ENERGY
INTENSITY
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. For comparison between years, the data for 2009 have been taken as the baseline (100%). For these indexes the
numerator represents consumption from primary resources and purchases of electricity and/or steam.
PEOPLE, HEALTH AND SAFETY
EMPLOYMENT
Eni uses a large number of contractors to carry out the activities within its own sites.
INDUSTRIAL
RELATIONS
SENIORITY
TRAINING
HOURS
LOCAL SENIOR
MANAGERS AND
MANAGERS
ABROAD
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 remote)
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 managers + managers (employees born in the Country in which their main working activity is based) divided
by total employment abroad.
(47) This view includes the following non-fully consolidated companies deemed significant from a HSE impacts standpoint: Mozambique Rovuma Venture SpA, Agiba Petroleum Co, Cardón IV
SA, Groupment Sonatrach-Agip, InAgip doo, Karachaganak Petroleum Operating BV, Llc “Westgasinvest”, Mellitah Oil & Gas BV, Petrobel Belayim Petroleum Co, United Gas Derivatives Co, Virginia
Indonesia Co Llc, Costiero Gas Livorno SpA, Petroven Srl, Servizio Fondo Bombole Metano SpA, Esacontrol SA, Tecnoesa SA, Oleoduc du Rhone SA, OOO Eni-Nefto, Eni Gas Transport Services Srl,
Versalis Congo Sarlu, Versalis Kimya Ticaret Limited Sirketi, Versalis Pacific (India) Private Limited, Società EniPower Ferrara Srl, EniProgetti Egypt Ltd.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2018 126
KPI
METHODOLOGY
SAFETY
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: indicator of frequency of injuries at work with serious consequences (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, of which the origin, execution and potential effect 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 2018 at Eni were found in the following types of activities:
• work at height: exposes workers to the risk of falls from a height. At Eni, this occurs especially for work that requires the use of
scaffolding or that involves the lifting of workers with a safety harness (man rigging);
• load handling: exposes workers to collisions, crushing, falls from a height or on the same plane mainly during the lifting of material
and the movement on the same plane of various types of materials.
HEALTH
Number of occupational disease reports presented 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: (i) due to exposure to chemical agents: neoplasms, respiratory diseases, blood diseases; (ii) due to
exposure to biological agents: malaria; (iii) due to exposure to physical agents: hypoacusis.
ENVIRONMENT
WATER
WITHDRAWAL
BY SOURCE
BIODIVERSITY
OIL SPILLS
WASTE
AIR
PROTECTION
Sum of sea water, freshwater, and salt water from subsoil or surface withdrawn. TAF (groundwater treatment plant) water represents
the amount of polluted groundwater treated and reused in the production cycle.
Number of sites overlapping with protected areas and Key Biodiversity Areas (KBAs): calculated by identifying the active national
and international concessions, whether operated or in joint ventures, under development or in production, present in the Company
databases (last updated in June 2018) that overlap with one or more protected or key biodiversity areas (data made available to
Eni by “World Database on Protected Areas” last updated in December 2018, and “World Database of Key Biodiversity Areas” last
updated in June 2018, in the framework of Eni’s membership in the UNEP-WCMC Proteus Partnership) where development/production
operations (wells, sealines, pipelines and onshore and offshore plants as documented in the company’s GIS geodatabase) overlap
with protected areas and/or KBAs.
Number of sites adjacent to protected areas or Key Biodiversity Areas (KBAs): concessions for which the overlap analysis
described above has not confirmed the presence of operational sites (development/production) overlapping protected areas or key
biodiversity areas, determining their position outside these areas.
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.
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.
NOX:total direct emissions of nitrogen oxide due to combustion processes with air. Includes emissions of NOx from flaring activities,
sulphur recovery processes, FCC regeneration, etc. 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.
PST: direct emissions of Total Suspended Particulates, finely divided solid or liquid material suspended in gaseous flows. Standard
emission factors.
SUPPLIERS
SUPPLIERS
SUBJECTED
TO
ASSESSMENT
This indicator relates to processes managed by Eni SpA, Eni Ghana and Eni Pakistan and represents all suppliers subjected to
Due Diligence, a qualification process, HSE, compliance or business conduct assessment feedback, human rights feedback
process or 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 and Eni Pakistan.
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION 127
KPI
METHODOLOGY
ANTI-CORRUPTION
ANTI-
CORRUPTION
TRAINING
E-learning for managers: online courses for managerial figures.
E-learning for other resources: online courses for non-managerial resources.
General workshop: in-class training events for staff at risk of corruption.
Job specific training: in-class training events for professional areas at risk of corruption.
LOCAL COMMUNITIES
SPENDING
TO LOCAL
SUPPLIERS
The indicator refers to the 2018 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): the portion paid in local currency is identified as spending to local suppliers;
3) “Country registration method” (Iraq e 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 list of Countries to which the expenditure indicator refers will be expanded starting from 2019.
GRIEVANCES
Complaints made by an individual or a group of individuals relating to actual or perceived impacts caused by the Company’s
operational activities.
Correlation table between the key sustainability topics for Eni and GRI Standards
KEY SUSTAINABILITY TOPICS
GRI STANDARDS
INTERNAL
BOUNDARY
EXTERNAL BOUNDARY
AND LIMITATIONS
O
T
H
T
A
P
N
O
I
T
A
Z
I
N
O
B
R
A
C
E
D
L
E
D
O
M
E
C
N
E
L
L
E
C
X
E
L
A
N
O
I
T
A
R
E
P
O
L
A
C
O
L
F
O
N
O
I
T
O
M
O
R
P
T
N
E
M
P
O
L
E
V
E
D
Combating climate change
GHG emissions, promotion of natural gas,
renewable, biofuels and green chemistry
GRI 201 Economic Performance
GRI 305 Emissions
GRI 302 Energy
Technological Innovation
-
People
Employment, diversity and inclusion
Training
Occupational health and local communities health
GRI 202 Market presence
GRI 401 Employment
GRI 403 Occupational H&S
GRI 404 Training and Education
GRI 405 Diversity of governance bodies and employees
Safety
People safety and asset integrity
Reduction of environmental impacts
Water resources
Biodiversity
Oil spill
Human Rights
Rights of workers and local communities
Supply chain
Security
Integrity in business management
Transparency and anti-corruption
Access to energy, local development through
public-private partnerships
Economic diversification
Education and training
Access to water and hygiene
Health
GRI 403 Occupational H&S
GRI 303 Water
GRI 304 Biodiversity
GRI 306 Effluents and Waste
GRI 307 Environmental compliance
GRI 406 Non-Discrimination
GRI 410 Security Practices
GRI 412 Human Rights Assessment
GRI 414 Supplier Social Assessment
GRI 205 Anti-corruption
GRI 203 Indirect Economic Impacts
GRI 413 Local Communities
Local content
GRI 204 Procurement Practices
(1) RNES: Reporting not extended to suppliers.
(2) RNEC: Reporting not extended to customers.
(3) RPES: Reporting partially extended to suppliers.
√
√
√
√
√
√
√
√
√
√
Suppliers
and customers
(RNES1; RNEC2)
Suppliers
Local security forces;
Suppliers
(RNES1)
Suppliers (RPES3)
Suppliers (RNES1)
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2018
128
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
Stakeholders 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 2018, p. 1
Annual Report 2018, p. 3
Location of headquarters
Location of operations
Ownership and legal form
Markets served
Scale of the organization
Annual Report 2018, inside back cover
Annual Report 2018, p. 3
Annual Report 2018, inside back cover
https://www.eni.com/en_IT/company/governance/shareholders.page
Annual Report 2018, p. 3
Annual Report 2018, pp. 12-13
NFI, pp. 114; 125
Information on employees and other workers
NFI, pp. 114; 125
Supply chain
NFI, p. 120
Significant changes to the organization and its supply chain
Annual Report 2018, pp. 146-149; 283
Precautionary Principle or approach
Annual Report 2018, pp. 20-23
External initiatives
Membership of associations
Annual Report 2018, p. 15
Annual Report 2018, p. 15
Statement from senior decision-maker
Annual Report 2018, pp. 7-11
Key impacts, risks, and opportunities
Annual Report 2018, pp. 20-23; 87-102
Values, principles, standards, and norms of behavior
Annual Report 2018, pp. 2; 4-5; 29
NFI, 106
Governance structure
Annual Report 2018, pp. 24-29
List of stakeholder groups
Annual Report 2018, pp. 14-15
Collective bargaining agreements
NFI, pp. 114; 125
Identifying and selecting stakeholders
Annual Report 2018, pp. 14-15
Approach to stakeholder engagement
Key topics and concerns raised
Annual Report 2018, pp. 14-15
Annual Report 2018, pp. 14-15
Entities included in the consolidated financial statements
Annual Report 2018, pp. 260-283
NFI, p. 125
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. 124; 127
NFI, pp. 124; 127
NFI, pp. 111; 118; 125
NFI, pp. 124; 127
NFI, p. 125
https://www.eni.com/en_IT/documentations.page
NFI, p. 125
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. 125; 128-130
NFI, pp. 131-133
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION
129
Specific Standard disclosures
DISCLOSURE INDICATOR DESCRIPTION
SECTION AND/OR PAGE NUMBER
OMISSION
CATEGORY: ECONOMIC METRICS AND COMMENTS
Economic performance - DMA (103-1; 103-2; 103-3)
NFI, pp. 106-111; 124; 127
201-2
Financial implications and other risks and opportunities due
to climate change
Annual Report 2018, pp. 22-23; 99-100
NFI, pp. 108-111
Market presence - DMA (103-1; 103-2; 103-3)
NFI, pp. 106-107; 112-114; 124-125; 127
202-2
Proportion of senior management hired from the local
community
NFI, pp. 113-114; 125
Indirect economic impacts - DMA (103-1; 103-2; 103-3)
NFI, pp. 106-107; 122-124; 127
203-1
Infrastructure investments and services supported
NFI, p. 123
Procurement practices - DMA (103-1; 103-2; 103-3)
NFI, pp. 106-107; 122-124; 127
204-1
Proportion of spending on local suppliers
NFI, pp. 122-123; 127
Anti-corruption - DMA (103-1; 103-2; 103-3)
NFI, pp. 106-107; 121-122; 124; 127
205-2
Communication and training about anti-corruption policies
and procedures
NFI, pp. 121-122; 127
CATEGORY: ENVIRONMENTAL METRICS AND COMMENTS
Energy - DMA (103-1; 103-2; 103-3)
NFI, pp. 106-111; 124-125; 127
302-3
Energy intensity
NFI, pp. 110-111; 125
Water - DMA (103-1; 103-2; 103-3)
NFI, pp. 106-107; 116-118; 124; 126-127
303-1
Water withdrawal by source
NFI, pp. 117-118; 126
Biodiversity - DMA (103-1; 103-2; 103-3)
NFI, pp. 106-107; 116-118; 124; 126-127
304-1
Operational sites owned, leased, managed in, or adjacent to,
protected areas and areas of high biodiversity value outside
protected areas
NFI, pp. 117; 126
The biodiversity disclosure
is limited to the upstream
sector only.
Emissions - DMA (103-1; 103-2; 103-3)
NFI, pp. 106-111; 124-125; 127
305-1
305-4
Direct (Scope 1) GHG emissions
GHG emissions intensity
NFI, pp. 110-111; 125
NFI, pp. 110-111; 125
Effluents and waste - DMA (103-1; 103-2; 103-3)
NFI, pp. 106-107; 116-118; 124; 126-127
306-2
306-3
Waste by type and disposal method
Significant spills
NFI, pp. 117-118; 126
NFI, pp. 117-118; 126
Environmental compliance - DMA (103-1; 103-2; 103-3)
NFI, pp. 106-107; 116-118; 124; 127
307-1
Environmental compliance
Annual Report 2018, pp. 205-209
CATEGORY: SOCIAL METRICS AND COMMENTS
Employment - DMA (103-1; 103-2; 103-3)
NFI, pp. 106-107; 112-114; 124-125; 127
401-1
New employee hires and employee turnover
NFI, pp. 113-114; 125
Occupational health and safety - DMA (103-1; 103-2; 103-3; 403-1; 403-2;
403-3; 403-4; 403-5; 403-6; 403-7)
NFI, pp. 106-107; 112-115; 124; 126-127
403-9
Work-related injuries
403-10
Work-related ill health
NFI, pp. 115; 126
NFI, pp. 113-114; 126
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATIONEni Annual Report 2018
130
DISCLOSURE INDICATOR DESCRIPTION
SECTION AND/OR PAGE NUMBER
OMISSION
Training and education - DMA (103-1; 103-2; 103-3)
NFI, pp. 106-107; 112-114; 124-125; 127
404-1
Average hours of training per year per employee
NFI, pp. 113-114; 125
Diversity and equal opportunity - DMA (103-1; 103-2; 103-3)
NFI, pp. 106-107; 112-114; 124; 127
405-1
Diversity of governance bodies and employees
NFI , pp. 113-114
Non-discrimination - DMA (103-1; 103-2; 103-3)
NFI, pp. 106-107; 118-120; 124; 127
406-1
Incidents of discrimination and corrective actions taken
NFI, pp. 119-120
Security practices - DMA (103-1; 103-2; 103-3)
NFI, pp. 106-107; 118-120; 124; 127
410-1
Security personnel trained in human rights policies
or procedures
NFI, pp. 119-120
Human rights assessment - DMA (103-1; 103-2; 103-3)
NFI, pp. 106-107; 118-120; 124; 127
412-2
Employee training on human rights policies or procedures
NFI, pp. 119-120
Local communities - DMA (103-1; 103-2; 103-3)
NFI, pp. 106-107; 122-124; 127
413-1
Operations with local community engagement, impact
assessments, and development programs
NFI, pp. 122-123
Supplier social assessment - DMA (103-1; 103-2; 103-3)
NFI, pp. 106-107; 120; 124; 126-127
414-1
New suppliers that were screened using social criteria
NFI, pp. 120; 126
CATEGORY: TECHNOLOGICAL INNOVATION
Innovation - DMA (103-1; 103-2; 103-3)
NFI, pp. 106-111; 124; 127
CONSOLIDATED DISCLOSURE OF NON-FINANCIAL INFORMATION
Independent auditors’ report
131
132
133
134
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 2018,
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, 2018, nine of Eni’s subsidiaries: Eni Congo
SA, Eni Petroleum Co Inc, Nigerian Agip Oil Co Ltd, Nigerian Agip
Exploration Ltd, Eni Finance USA Inc, Eni Trading & Shipping Inc,
Eni Canada Holding Ltd, Eni Turkmenistan Ltd and Eni Ghana
Exploration and Production Ltd - 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.
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.
GLOSSARY
135
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.
| 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.
| 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.
| Boe (Barrel of Oil Equivalent) Is used as a standard unit
| Mineral Potential (Potentially recoverable hydrocarbon
measure for oil and natural gas. From July 1, 2012, Eni has
updated the conversion rate of gas to 5,492 cubic feet of gas
equals 1 barrel of oil (it was 5,550 cubic feet of gas per barrel in
previous reporting periods).
| 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.
| Green House Gases (GHG) Gases in the atmosphere, transparent
to solar radiation, can consistently trap infrared radiation emitted
by the earth’s surface, atmosphere and clouds. The six relevant
greenhouse gases covered by the Kyoto Protocol are carbon dioxide
(CO2), methane (CH4), nitrous oxide (N2O), hydrofluorocarbons
(HFCs), perfluorocarbons (PFCs) and sulfur hexafluoride (SF6).
GHGs absorb and emit radiation at specific wavelengths within
the range of infrared radiation determining the so called
greenhouse phenomenon and the related increase of earth’s
average temperature. Eni’s emissions are reported in CO2
equivalent (CO2eq) because they include not only carbon dioxide
but also other climating gases as methane (CH4) and nitrouse
oxide (N2O), characterized by a conversion factor of 25 and 298
respectively (source: IPCC).
| 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.
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.
| 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.
| 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.
| 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
know reservoirs, and under existing economic conditions.
136
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.
| 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
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.
| 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 chemicals products.
| 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.
| Workover Intervention on a well for performing significant
according to which the purchaser is bound to pay the contractual
price or a fraction of such price for a minimum quantity of the
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
2018
2 |
M A N A G E M E N T R E P O R T
1 3 7 |
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 5 9 |
A N N E X
138
146
237
252
253
138138
CONSOLIDATED BALANCE SHEET
(€ million)
ASSETS
Current assets
Cash and cash equivalents
Financial assets held for trading
Financial assets available for sale
Other current financial assets
Trade and other receivables
Inventories
Income tax receivables
Other tax receivables
Other current assets
Non-current assets
Property, plant and equipment
Inventory - compulsory stock
Intangible assets
Equity-accounted investments
Other investments
Other non-current financial assets
Deferred tax assets
Other non-current assets
Assets held for sale
TOTAL ASSETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term debt
Current portion of long-term debt
Trade and other payables
Income tax payables
Other tax payables
Other current liabilities
Non-current liabilities
Long-term debt
Provisions for contingencies
Provisions for employee benefits
Deferred tax liabilities
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 (loss)
Total Eni shareholders’ equity
TOTAL SHAREHOLDERS’ EQUITY
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
December 31, 2018
December 31, 2017
Note
Total amount
of which with
related parties
Total amount
of which with
related parties
73
834
30
1,214
46
164
2,808
60
23
(5)
(6)
(15)
(7)
(8)
(9)
(9)
(10) (23)
(11)
(8)
(12)
(14)
(14)
(15)
(22)
(10) (23)
(24)
(18)
(18)
(16)
(9)
(9)
(17) (23)
(18)
(20)
(21)
(22)
(17) (23)
(24)
(25)
10,836
6,552
300
14,101
4,651
191
561
2,258
39,450
60,302
1,217
3,170
7,044
919
1,253
3,931
792
78,628
295
118,373
2,182
3,601
16,747
440
1,432
3,980
28,382
20,082
11,886
1,117
4,272
1,502
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
49
633
71
915
160
661
3,664
63
23
7,363
6,012
207
316
15,421
4,621
191
729
1,573
36,433
63,158
1,283
2,925
3,511
219
1,675
4,078
1,323
78,172
323
114,928
2,242
2,286
16,748
472
1,472
1,515
24,735
20,179
13,447
1,022
5,900
1,479
42,027
87
66,849
49
4,005
35,966
4,818
1,889
(581)
(1,441)
3,374
48,030
48,079
114,928
CONSOLIDATED FINANCIAL STATEMENTS 2018 | FINANCIAL STATEMENTS
CONSOLIDATED PROFIT AND LOSS ACCOUNT
139139
(€ million)
REVENUES
Net 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
Write-off of tangible and intangible assets
OPERATING PROFIT (LOSS)
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 (LOSS) BEFORE INCOME TAXES
Income taxes
Net profit (loss) for the year - continuing operations
Net profit (loss) for the year - discontinued operations
Net profit (loss) for the year
Attributable to Eni:
- continuing operations
- discontinued operations
Attributable to non-controlling interest:
- continuing operations
- discontinued operations
Earnings per share attributable to Eni (€ per share)
Basic
Diluted
Earnings per share attributable to Eni – Continuing operations
(€ per share)
Basic
Diluted
(33)
(33)
2018
2017
2016
Total
amount
of which with
related parties
Total
amount
of which with
related parties
Total
amount
of which with
related parties
Note
(28)
75,822
1,116
76,938
1,383
8
66,919
4,058
70,977
1,567
41
55,762
931
56,693
1,238
74
(29)
(55,622)
(8,009)
(51,548)
(9,164)
(43,278)
(8,212)
(7)
(29)
(23)
(11) (12)
(13)
(11) (12)
(30)
(30)
(30)
(23)
(14) (31)
(32)
(24)
247
157
(145)
27
(415)
(3,093)
129
(6,988)
(866)
(100)
9,983
3,967
(4,663)
32
(307)
(971)
(68)
1,163
1,095
10,107
(5,970)
4,137
4,137
4,126
4,126
11
11
1.15
1.15
1.15
1.15
26
(22)
319
(913)
(2,951)
(32)
(7,483)
225
(263)
8,012
(34)
331
(846)
(2,994)
16
(7,559)
475
(350)
2,157
115
(283)
3,924
(5,886)
191
(4)
5,850
(6,232)
(111)
837
(1,236)
(267)
335
68
6,844
(3,467)
3,377
3,377
3,374
3,374
3
3
0.94
0.94
0.94
0.94
(21)
(482)
(885)
(326)
(54)
(380)
892
(1,936)
(1,044)
(413)
(1,457)
(1,051)
(413)
(1,464)
7
7
(0.41)
(0.41)
(0.29)
(0.29)
CONSOLIDATED FINANCIAL STATEMENTS 2018 | FINANCIAL STATEMENTSEni Annual Report 2018
140140
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS)
(€ million)
Net profit (loss)
Other items of comprehensive income (loss)
Items that are not reclassified to profit or loss in later periods
Remeasurements of defined benefit plans
Fair value valuation of minor investments with effect to other comprehensive income
Tax effect related to other comprehensive income not to be reclassified
to profit or loss in subsequent periods
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 on equity-accounted entities
Tax effect related to other comprehensive income
to be reclassified to profit or loss in subsequent periods
Total other items of comprehensive income (loss)
Total comprehensive income (loss)
Attributable to Eni
- continuing operations
- discontinued operations
Attributable to non-controlling interest
- continuing operations
- discontinued operations
2017
3,377
2016
(1,457)
(33)
16
Note
(25)
(25)
(25)
(25)
(25)
(25)
(25)
2018
4,137
(15)
15
(2)
(2)
1,787
(243)
(24)
58
1,578
1,576
5,713
29
(4)
(5,573)
(5)
(6)
69
1
(5,514)
(5,518)
(2,141)
5,702
(2,144)
5,702
(2,144)
11
11
3
3
(35)
(19)
1,198
(4)
883
32
(220)
1,889
1,870
413
819
(413)
406
7
7
CONSOLIDATED FINANCIAL STATEMENTS 2018 | FINANCIAL STATEMENTS
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
141141
Eni shareholders’ equity
s
e
c
n
e
r
e
ff
d
n
o
i
t
a
i
l
s
n
a
r
t
y
c
n
e
r
r
u
c
e
v
i
t
a
l
u
m
u
C
s
g
n
i
n
r
a
e
d
e
n
i
a
t
e
R
l
a
t
i
p
a
c
e
r
a
h
S
s
e
v
r
e
s
e
r
r
e
h
t
O
s
e
r
a
h
s
y
r
u
s
a
e
r
T
d
n
e
d
i
v
i
d
m
i
r
e
t
n
I
r
a
e
y
e
h
t
r
o
f
)
s
s
o
l
(
t
fi
o
r
p
t
e
N
4,005
4,005
35,966
245
36,211
4,818
1,889
(581)
(1,441)
3,374
4,818
1,889
(581)
(1,441)
3,374
4,126
(17)
15
(2)
(185)
(24)
(209)
(211)
1,787
1,787
1,787
4,126
l
a
t
o
T
48,030
245
48,275
4,126
(17)
15
(2)
1,787
(185)
(24)
1,578
5,702
1,441
(2,881)
(1,440)
(1,513)
(1,513)
t
s
e
r
e
t
n
i
g
n
i
l
l
o
r
t
n
o
c
-
n
o
N
49
49
11
11
(3)
y
t
i
u
q
e
’
s
r
e
d
l
o
h
e
r
a
h
s
l
a
t
o
T
48,079
245
48,324
4,137
(17)
15
(2)
1,787
(185)
(24)
1,578
5,713
(1,440)
(1,513)
(3)
493
493
5
(7)
(2)
36,702
(493)
(3,374)
(72)
(2,953)
(3)
(2,956)
(6)
(6)
1,672
6,605
(581)
(1,513)
4,126
5
(13)
(8)
51,016
5
(13)
(8)
51,073
57
e
t
o
N
(25)
(3)
(25)
(25)
(25)
(25)
(25)
(25)
(25)
(€ 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 recognised in 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” on
equity-accounted entities
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
Balance at December 31, 2018
(25)
4,005
CONSOLIDATED FINANCIAL STATEMENTS 2018 | FINANCIAL STATEMENTSEni Annual Report 2018
142142
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY (continued)
Eni shareholders’ equity
s
e
c
n
e
r
e
ff
d
n
o
i
t
a
i
l
s
n
a
r
t
y
c
n
e
r
r
u
c
e
v
i
t
a
l
u
m
u
C
s
g
n
i
n
r
a
e
d
e
n
i
a
t
e
R
l
a
t
i
p
a
c
e
r
a
h
S
e
t
o
N
s
e
v
r
e
s
e
r
r
e
h
t
O
s
e
r
a
h
s
y
r
u
s
a
e
r
T
d
n
e
d
i
v
i
d
m
i
r
e
t
n
I
r
a
e
y
e
h
t
r
o
f
)
s
s
o
l
(
t
fi
o
r
p
t
e
N
t
s
e
r
e
t
n
i
g
n
i
l
l
o
r
t
n
o
c
-
n
o
N
y
t
i
u
q
e
’
s
r
e
d
l
o
h
e
r
a
h
s
l
a
t
o
T
l
a
t
o
T
(25)
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” on
equity-accounted entities
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
(25)
(25)
(25)
(25)
(25)
(25)
(25)
Balance at December 31, 2017
(25)
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 2018 | FINANCIAL STATEMENTS
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY (continued)
143143
Eni shareholders’ equity
s
e
c
n
e
r
e
ff
d
n
o
i
t
a
i
l
s
n
a
r
t
y
c
n
e
r
r
u
c
e
v
i
t
a
l
u
m
u
C
s
g
n
i
n
r
a
e
d
e
n
i
a
t
e
R
l
a
t
i
p
a
c
e
r
a
h
S
s
e
v
r
e
s
e
r
r
e
h
t
O
s
e
r
a
h
s
y
r
u
s
a
e
r
T
d
n
e
d
i
v
i
d
m
i
r
e
t
n
I
r
a
e
y
e
h
t
r
o
f
t
fi
o
r
p
t
e
N
l
a
t
o
T
t
s
e
r
e
t
n
i
g
n
i
l
l
o
r
t
n
o
c
-
n
o
N
y
t
i
u
q
e
’
s
r
e
d
l
o
h
e
r
a
h
s
l
a
t
o
T
4,005
51,985
9,129
1,173
(581)
(1,440)
(8,778)
(1,464)
55,493
(1,464)
1,916
7
57,409
(1,457)
(19)
(19)
8
(4)
663
32
699
680
1,190
1,190
1,190
(1,028)
(10,630)
(11,658)
(19)
(19)
1,198
(4)
663
32
1,889
406
(1,464)
1,440
(1,852)
(1,440)
(1,441)
(1,441)
(19)
(19)
1,198
(4)
663
32
1,889
413
(1,440)
(1,441)
(4)
7
(4)
10,630
8,778
(1)
(2,881)
(4)
(2,885)
(8)
48
40
40,367
10,319
(20)
(1)
(21)
1,832
(581)
(1,441)
(1,464)
(1,872)
(1,872)
(28)
47
19
53,037
2
(1,870)
49
(28)
49
(1,851)
53,086
(€ milioni)
Balance at December 31, 2015
Net profit (loss) 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”
on equity-accounted entities
Total comprehensive income (loss) of the year
Transactions with shareholders
Dividend distribution of Eni SpA (€0.40 per share in
settlement of 2015 interim dividend of €0.40 per share)
Interim dividend distribution of Eni SpA
(€0.40 per share)
Dividend distribution of other companies
Allocation of 2015 net loss
Other changes in shareholders’ equity
Exclusion from the scope of consolidation of Saipem
group following the sale of the control
Reclassification to profit and loss account
of amounts previously recognized in other
comprehensive income related to Saipem
Other changes
Balance at December 31, 2016
4,005
CONSOLIDATED FINANCIAL STATEMENTS 2018 | FINANCIAL STATEMENTSEni Annual Report 2018
14 414 4
15
334
642
(238)
879
CONSOLIDATED STATEMENT OF CASH FLOWS
(€ million)
Net profit (loss) of the year - continuing operations
Adjustments to reconcile net profit (loss) to net cash provided by operating
activities
Depreciation and amortization
Net Impairments (reversals) of tangible and intangible 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 for contingencies
- other assets and liabilities
Cash flow from changes in working capital
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
- intangible assets
- consolidated subsidiaries and businesses net
of cash and cash equivalent acquired
- investments
- securities
- financial receivables
- change in payables in relation to investing activities
and capitalized depreciation
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
- financial receivables
- change in receivables in relation to disposals
Cash flow from disposals
Net cash used in investing activities
- of which with related parties
Note
(11) (12)
(13)
(11) (12)
(14) (31)
(31)
(32)
(36)
(11)
(12)
(26)
(14)
(26)
(36)
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)
(432)
(554)
408
(9,941)
1,089
5
(47)
195
61
496
606
2,405
(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)
(316)
(657)
152
(10,012)
2,745
2
2,662
(436)
482
224
999
(434)
6,244
(3,768)
(3,115)
(273)
1,286
1,495
(1,043)
647
2016
(1,044)
7,559
(475)
350
326
(48)
(143)
(209)
645
1,936
(9)
2,112
22
212
160
(780)
(2,941)
7,673
(3,749)
(9,067)
(113)
(1,164)
(1,336)
(1,208)
(8)
(12,896)
19
(362)
508
20
8,063
205
8,453
(4,443)
3,752
CONSOLIDATED FINANCIAL STATEMENTS 2018 | FINANCIAL STATEMENTS
145145
CONSOLIDATED STATEMENT OF CASH FLOWS (continued)
(€ million)
Increase in long-term financial debt
Repayments of long-term financial debt
Increase (decrease) in short-term financial debt
Dividends paid to Eni’s shareholders
Dividends paid to non-controlling interest
Net cash used in financing activities
- of which with related parties
Effect of change in consolidation (inclusion/exclusion of significant/insignificant subsidiaries)
Effect of cash and cash equivalents pertaining to discontinued operations
Effect of exchange rate changes and other changes on cash and cash equivalents
Net cash flow of the year
Cash and cash equivalents - beginning of the year
Cash and cash equivalents - end of the year(a)
Note
(18)
(18)
(18)
(36)
(5)
(5)
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
2016
4,202
(2,323)
(2,645)
(766)
(2,881)
(4)
(3,651)
(192)
(5)
889
2
465
5,209
5,674
(a) Cash and cash equivalents as of December 31, 2018, include €19 million of cash and cash equivalents of consolidated subsidiaries held for sale that were reported in the item Assets held for sale
in the balance sheet.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | FINANCIAL STATEMENTSEni Annual Report 2018
146
NOTES ON CONSOLIDATED FINANCIAL
STATEMENTS
assumptions used. The accounting estimates and judgements
relevant for the preparation of the Consolidated Financial Statement
are described below.
1 | Significant accounting policies, estimates
and judgements
PRINCIPLES OF CONSOLIDATION
BASIS OF PREPARATION
The Consolidated Financial Statements of the Eni Group have been
prepared 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 Legislative Decree No. 38/052. Oil and
natural gas exploration and production activity is accounted for in
accordance with internationally accepted accounting standards
taking into account the applicable IFRS requirements.
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 2018 Consolidated Financial Statements, approved by the
Eni’s Board of Directors on March 14, 2019, were audited by the
external auditor EY 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, EY SpA takes the responsibility of their work.
The Consolidated Financial Statements are presented in euro 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 fixed assets, intangible assets
and goodwill, decommissioning and restoration liabilities, business
combinations, employee benefits and recognition of environmental
liabilities. Although the Company uses its best estimates and
judgements, actual results could differ from the estimates and
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 in 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 not
significant, either individually or in the aggregate; this exclusion
has not produced significant3 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 re-measurement of any investment
retained in the former subsidiary at its fair value; and (iii) any
amount related to the former subsidiary previously recognised
(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 2018.
(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, 2018”.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 147
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.
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. Not significant joint operations
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”.
Investments in subsidiaries, joint arrangements and associates as
of December 31, 2018 are presented separately in the annex “List of
companies owned by Eni SpA as of December 31, 2018”. This annex
includes also the changes in the scope of consolidation.
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 not significant
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 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; 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”). When
there is objective evidence of impairment (e.g. relevant breaches
of contracts, significant financial difficulty, probable default of the
counterparty, etc.), the recoverability is tested by comparing the
carrying amount and the related recoverable amount determined by
adopting the criteria indicated in the accounting policy for “Property,
plant and equipment”. When an impairment loss no longer exists or
has decreased, a reversal of the impairment loss is recognised in the
profit and loss account within “Other gain (loss) from investments”.
The impairment reversal shall not exceed the previously recognised
impairment losses. 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 of any financing
receivables towards the investee for which settlement is neither
planned nor likely to occur in the foreseeable future and which are,
in substance, an extension of the investment in the investee (the
so-called long-term interests).
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 re-
measurement 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.
The investor’s share of losses of an investee, that exceeds the
carrying amount of the investment and any long-term interests, 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.
(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.
(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 not significant unconsolidated subsidiaries are accounted for at cost less any accumulated impairment losses, if this does not result in a misrepresentation of the
Company’s financial position and performance.
(8) If the retained investment continues to be accounted for using the equity method, no re-measurement 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 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 148
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.
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 net of the
acquisition-date amounts of the identifiable assets acquired and
liabilities assumed is recognised, in 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, hence, 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 re-measured 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.
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 euro 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 the Eni shareholders’ equity
“Cumulative currency translation differences”12. 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 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 euro 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 below in the accounting policy for “Fair value measurements”.
(11) The choice between 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) 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 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 149
(currency amount for 1 €)
US Dollar
Pound Sterling
Norwegian Krone
Australian Dollar
Annual average
exchange rate
2018
Exchange rate
at December
31, 2018
Annual average
exchange rate
2017
Exchange rate
at December
31, 2017
Annual average
exchange rate
2016
Exchange rate
at December
31, 2016
1.18
0.88
9.60
1.58
1.15
0.89
9.94
1.62
1.13
0.88
9.33
1.47
1.20
0.89
9.83
1.53
1.11
0.82
9.29
1.49
1.05
0.86
9.09
1.46
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 EXPENDITURE
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 can show the existence 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, as well as whether 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 EXPENDITURE
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”.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 150
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
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.
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 and 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.
DECOMMISSIONING AND RESTORATION LIABILITIES
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, consistently 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 any reserve
estimate depends on the quality of available data, the engineering and
geological interpretation of such data and management’s judgement.
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 carried 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. Eni reassesses its estimate
of proved reserves periodically. The estimated proved reserves of
oil and natural gas may be subject to future revision. Upward or
downward revision may be made to the initial booking of reserves due
to production, reservoir performance, commercial factors, acquisition
and divestment activity and additional reservoir development activity.
In particular, changes in oil and natural gas prices could impact the
amount of Eni’s proved reserves in regards to the initial estimate and, in
the case of production sharing agreements and buy-back contracts, the
share of production and reserves to which Eni is entitled. Accordingly,
the estimated reserves could be materially different from the quantities
of oil and natural gas that ultimately will be recovered. Oil and natural
gas reserves have a direct impact on certain amounts reported in the
Consolidated Financial Statements. 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 using the
UOP method. Conversely, a decrease in estimated proved developed
reserves increases depreciation, amortisation and depletion charge.
Estimated proved reserves are affected, inter alia, by the trend of
reference oil and gas commodity prices and by the specific legal
agreement for the Oil & Gas activity.
In addition, estimated proved reserves are used to calculate future
cash flows from Oil & Gas properties, which are used to assess any
impairment loss.
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.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 151
In the case of a present obligation for dismantling and removal
of assets and restoration of sites, the initial carrying amount of
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). Changes resulting from revisions to the timing or the
amount of the original estimate of the provision are accounted for
as described in the accounting policy for “Provisions, contingent
liabilities and contingent assets”13.
Property, plant and equipment are not revalued for financial
reporting purposes.
Assets held under finance lease, or under arrangements that do not
take the legal form of a finance lease but substantially transfer all
the risks and rewards incidental to ownership of the leased asset,
are recognised, at the commencement of the lease term, at their
fair value, net of grants attributable to the lessee or, if lower, at the
present value of the minimum lease payments. Leased assets are
included within property, plant and equipment. A corresponding
financing payable to the lessor is recognised.
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, using a straight-line method
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. Leasehold improvement costs are depreciated over the useful
life of the improvements or, if lower, over the residual length of the lease,
considering any renewal period if renewal depends entirely on the lessee
and is virtually certain. Expenditures for ordinary maintenance and
repairs are recognised as an expense as incurred.
The carrying amount of property, plant and equipment is reviewed
for impairment whenever there is any indication that the carrying
amounts of those assets may not be recoverable. The recoverability
of an asset is assessed by comparing its carrying amount with the
recoverable amount, which is the higher of the asset’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 asset 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. 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 asset,
giving greater weight to external evidence.
With reference to commodity prices, management assumes the price
scenario adopted for economic and financial projections and for whole
life appraisal for capital expenditures. In particular, for the cash flows
associated to 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.
Discounting is carried out at 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 expected 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 asset.
These adjustments are measured considering information from
external parties. WACC differs considering the risk associated with
each operating segments 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 with Eni
as a whole, specific WACC rates have been defined on the basis of
a sample of companies operating in the same segment/business,
adjusted to take into consideration the risk premium of the specific
Country of the activity. 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 deriving, through an
iteration process, from a post-tax valuation. Valuation is carried out
for each single asset or, if the recoverable amount of a single asset
cannot be determined, for the smallest identifiable group of assets
that generates independent cash inflows from their continuous
use, the so-called “cash-generating unit”. 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.
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.
(13) These liabilities relate essentially to assets in the Exploration & Production segment. Decommissioning and restoration liabilities associated with tangible assets of Refining & Marketing
and Chemicals and Gas & Power segments are recognised when the cost is actually incurred and the amount of the liability can be reliably estimated, considering that undetermined settlement
dates for assets dismantlement and restoration do not allow a discounting estimate of the obligation. With regard to this, Eni performs periodic reviews of its tangible assets of Refining &
Marketing and Chemicals and Gas & Power segments for any changes in facts and circumstances that might require recognition of a decommissioning and restoration liability.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 152
INTANGIBLE ASSETS
GRANTS RELATED TO 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. Their carrying amounts are tested for impairment at
least annually and whenever there is any indication of impairment.
Goodwill is tested for impairment at the lowest level within the entity
at which it is monitored for internal management purposes. When
the carrying amount of the cash-generating unit, including goodwill
allocated thereto, calculated considering any impairment loss of the
non-current assets belonging to the cash-generating unit, exceeds
its recoverable amount14, 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 unit, up to the recoverable amount of assets with
finite useful lives. An impairment loss recognised for goodwill is not
reversed in a subsequent period15.
Costs of obtaining a contract with a customer are recognised in
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
impairment16.
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 arising gain or loss is recognised in the profit
and loss account.
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 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
the 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
Non-financial assets are impaired 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
(14) For the definition of recoverable amount see the accounting policy for “Property, plant and equipment”.
(15) Impairment losses recognised 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.
(16) The previous accounting policies required the capitalisation of directly attributable customer acquisition costs when the following conditions are 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.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 153
proved reserve quantities or significant increase of the estimated
development 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, the effects
of inflation and technology improvements on operating expenses,
production profiles and the outlook for demand and supply conditions
on a global or regional scale. Similar remarks are valid for assessing
the physical recoverability of assets recognised in 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, as well as for assessing the
recoverability of deferred tax assets (see also accounting policy for
“Income taxes”), which requires complex processes for evaluating the
existence of adequate future taxable profit.
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 the commodity future 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 INSTRUMENTS17
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;
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 losses18 (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
income, is reclassified to the profit and loss account when the
financial asset is derecognised.
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 (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.
(17) The accounting policies related to financial instruments were defined on the basis of IFRS 9 “Financial Instruments” effective from 2018; as required by the standard, the new requirements have been
applied starting from January 1, 2018 without restating the prior years under comparison. With reference to the financial instruments held by the Company, the previous accounting policies (see 2017
Annual Report on Form 20-F) 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).
(18) Receivables and other financial assets measured at amortised cost are presented in the balance sheet net of their loss allowance.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 154
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 counterparties19.
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 reversals
(losses) of trade and other receivables”.
The financing receivables held for operating purposes, granted to
associates and joint ventures, which in substance form part of the
entity’s net investment in these investees, are tested for impairment
considering also the underlying industrial operations and the
macroeconomic scenarios of the Countries where the investees operate.
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 collaterals 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”. 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 quantity of the hedged item and the quantity of the hedging
instrument (the so-called hedge ratio) consistently 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 no longer 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.
(19) For exposures arising from intragroup transactions, the recovery rate is assumed equal to 100% taking into account the possibility to provide capital injections of investees.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 155
The entity 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 continue 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 in 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)”.
Where an obligation exists for an item of property, plant and
equipment (e.g. site dismantling and restoration), the provision is
recognised together with a corresponding amount as part of the
related item of property, plant and equipment. The decommissioning
portion of the property, plant and equipment is subsequently
depreciated at the same rate as the rest of the asset.
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, or,
when the liability regards tangible assets (e.g. site dismantling
and restoration), changes in the provision are recognised with a
corresponding entry to the assets to which they refer, to the extent
of the assets’ carrying amounts; any excess amount is recognised
in the profit and loss account.
Contingent liabilities are: (i) possible, but not probable 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 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.
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 and 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.
Where the effect of the time value of money is material, the amount
recognised as provision is the present value of the expenditures
expected to be required to settle the obligation. After the initial
recognition, the carrying amount of decommissioning and
restoration liabilities is adjusted to reflect the passage of time and
any change in the estimates following the modification of amount
and timing of future cash flows and discount rates adopted. The
discount rate used to determine the provision is based on complex
managerial judgements.
As other Oil & Gas companies, Eni is subject to numerous EU,
national, regional and local environmental laws and regulations
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 156
concerning its Oil & Gas operations, production and other activities.
They include legislations that implement international conventions
or protocols. Environmental provisions are recognised when it
becomes probable that an outflow of resources will be required to
settle the obligation and such obligation can be reliably estimated.
Management, considering the actions already taken, insurance
policies obtained to cover environmental risks and provision for
risks accrued, 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 liabilities related to environmental and
decommissioning and restoration liabilities, Eni recognises
provisions primarily related to legal, trade and tax 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 interests
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)”.
Re-measurements 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
comprehensive income. Re-measurements 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 re-measurements are taken to
profit and loss account in their entirety.
SHARE-BASED PAYMENTS
The line item “Payroll and related costs” includes the cost of
the share-based incentive plan, consistently with its actual
remunerative nature20. 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 and changes in health status of the participants; 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 re-measurements, comprising, among others,
changes in the current actuarial assumptions, differences in the
previous actuarial assumptions and what has actually occurred and
differences in the return on plan assets, excluding amounts included
in net interest, usually occur.
(20) The current share-based incentive plan, to be settled by treasury shares, was approved by the shareholders’ meeting held on April 13, 2017.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 157
Similarly 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.
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 CUSTOMERS21
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 sold22.
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, 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 (for example
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 revenues.
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 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, as well as they rely on other factors,
considered by the management, which can impact on them. 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 entity 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, determined on the
basis of the 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 and, if applicable, purchased emission rights
are considered the first to be sold. Monetary receivables granted to
replace the free award emission rights are recognised as a contra to
the line item “Other income and revenues”.
Lease payments under an operating lease are recognised as
an expense over the lease term. 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.
(21) The previous accounting policies about revenue are described in the 2017 Annual Report on Form 20-F.
(22) In accordance with the previous accounting policy (entitlement method), 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. In 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 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 158
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 at the date of the general shareholders’
meeting in which they were declared, except when the sale of shares
before the ex-dividend date is certain.
INCOME TAXES
Current income taxes are determined on the basis of estimated taxable
profit. The estimated liability is included in “Income tax payables”.
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. Income tax assets that are uncertain in
the amount to be recovered are recognised in accordance with the
probable threshold.
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 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.
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
in 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 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 takes place, 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, 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
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 159
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 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 | Financial statements23
Assets and liabilities on the balance sheet are classified as current
and non-current. Items on the profit and loss account are presented
by nature24. 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
(loss) integrated with income and expenses that are not recognised
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
IFRS 15 “Revenue from Contracts with Customers” and the document
“Clarifications to IFRS 15 Revenue from Contracts with Customers”
(hereinafter IFRS 15), which set out the requirements for recognising
and measuring revenue arising from contracts with customers, have
been adopted by the Commission Regulations No. 2016/1905 and
2017/1987 issued by the European Commission, respectively, on
September 22, 2016 and October 31, 2017.
Eni has applied IFRS 15 starting from January 1, 2018, by recognising,
in accordance with the transition requirements of the standard, the
cumulative effect of initially applying IFRS 15 as an adjustment to the
opening balance of equity as of January 1, 2018, taking into account
the contracts existing at that date, without restating the comparative
information. In particular, the adoption of IFRS 15 resulted in a decrease
in equity of €49 million arising from:
(i) a negative change of €103 million (€259 million before taxes) in
the Exploration & Production segment, related to the accounting
for amounts of production lifted by a partner within Oil & Gas
operations different from its proportionate entitlement (the so-
called lifting imbalances), by recognising revenue on the basis
of the quantities actually sold (the so-called sales method)
instead of the entitled quantities (the so-called entitlement
method); costs are recognised on the basis of the quantities
actually sold. Moreover the adoption of sales method resulted
in the reclassification of underlifting assets (quantities lifted
smaller than the entitled ones) and overlifting liabilities
(quantities lifted higher than the entitled ones), represented as
(23) The impacts on the financial statements arising from the adoption, starting from January 1, 2018, of the new IFRSs, as well as the other changes in the financial statements are described in the note
3 – Changes in accounting policies.
(24) Further information about classification of financial instruments is provided in note 27 – Guarantees, commitments and risks - Other information about financial instruments.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 160
receivables and payables under the entitlement method, into
the other assets and liabilities;
(ii) a positive change of €60 million (€87 million before taxes),
related to the capitalisation of the costs of obtaining contracts
with customers in the Gas & Power segment, net of their
amortisation;
(iii) a negative change of €6 million of equity-accounted investments.
IFRS 9 “Financial Instruments” (hereinafter IFRS 9) has been
adopted by the Commission Regulation No. 2016/2067 issued
by the European Commission on November 22, 2016. Eni has
applied IFRS 9 starting from January 1, 2018. As allowed by
the transition requirements of the standard, considering also
the complexity of the restatement at the beginning of the first
comparative year without the use of hindsight, the impacts
of the new classification and measurement requirements,
including impairment, of financial assets, have been recognised
as an adjustment to the opening balance of equity as of
January 1, 2018, without restating the comparative information;
with reference to hedge accounting, the adoption of the new
requirements did not have significant impacts.
In particular, the adoption of IFRS 9 resulted in an increase in
equity of €294 million arising from the fair value measurement of
investments in equity instruments previously measured at cost
(€681 million), partially offset by the additional impairment losses
(€356 million) of trade and other receivables (€427 million before
taxes), recognised under the expected credit loss model and by the
decrease of the carrying amount of equity-accounted investments
(€31 million).
As indicated in the accounting policy for “Investments in equity
instruments”, Eni elected to designate the investments in equity
instruments, held as of January 1, 2018, as assets measured at
FVTOCI.
Moreover, with reference to the classification and measurement of
financial assets, Eni reclassified the portfolio of financial assets
previously classified as available for sale into the financial assets
measured at FVTPL (€207 million), on the basis of the facts and
circumstances existing as of January 1, 2018.
The breakdown of the abovementioned quantitative effects and
reclassifications25, deriving from the initial application, as of
January 1, 201826, of IFRS 9 and IFRS 15, is as follows:
(€ million)
Selected line items only
Current assets
- of which: Financial assets held for trading
- of which: Financial assets available for sale
- of which: Other current financial assets
- of which: Trade and other receivables
- of which: Other current assets
Non-current assets
- of which: Intangible assets
- of which: Equity-accounted investments
- of which: Other investments
- of which: Deferred tax assets
Current liabilities
- of which: Trade and other payables
- of which: Other current liabilities
Non-current liabilities
- of which: Deferred tax liabilities
December
31, 2017
Adoption of
IFRS 9
Adoption of
IFRS 15 Reclassifications
Total effect
of the first
application
As restated
January
1, 2018
36,433
6,012
207
316
15,421
1,573
78,172
2,925
3,511
219
4,078
24,735
16,748
1,515
42,027
5,900
(427)
(372)
(427)
(372)
721
(31)
681
71
247
87
(6)
166
(113)
(113)
37
37
207
(207)
(466)
466
(1,330)
1,330
(799)
207
(207)
(1,265)
466
968
87
(37)
681
237
(113)
(1,443)
1,330
37
37
35,634
6,219
316
14,156
2,039
79,140
3,012
3,474
900
4,315
24,622
15,305
2,845
42,064
5,937
Shareholders’ equity
48,079
294
(49)
245
48,324
With reference to year 2018, the application of the previous revenue
recognition requirements does not have a significant impact on the
Consolidated Financial Statements.
For each kind of financial assets adjusted/reclassified upon the initial
application of IFRS 9, the table below provides for the following information:
(i) the original measurement category determined in accordance with
IAS 39; (ii) the new measurement category determined in accordance
with IFRS 9; (iii) the carrying amounts determined in accordance with
IAS 39, recognised as of December 31, 2017, and the carrying amounts
determined in accordance with IFRS 9 as of January 1, 2018.
(25) Under IFRS 15, short-term advances from customers have been reclassified from the line item “Trade and other payables” into the line item “Other current liabilities” of the balance sheet in order to
present them together with the other current contract liabilities (e.g. customer loyalty programs, deferred income, etc.), already recognised within such line item.
(26) The IFRIC Interpretation 22 “Foreign Currency Transactions and Advance Consideration” is also effective starting from January 1, 2018, but it did not have a significant impact on the Consolidated
Financial Statements.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
161
(€ milioni)
Financial assets
Financial assets held for trading
Financial assets available for sale
Trade and other receivables(**)
Other investments
Total
Classification
under IAS 39
Classification
under IFRS 9
Carrying
amount
under IAS 39
Adjustments Reclassifications
Other
changes(*)
Carrying
amount
under IFRS 9
Held for trading
Available-for-sale
Financing
receivables
Cost
FVTPL
FVTPL
Amortized
cost
FVTOCI
6,012
207
15,421
219
21,859
(427)
681
254
207
(207)
6,219
14,156
900
21,275
(838)
(838)
(*) Other changes result from the effects related to a different classification under IFRS 15 of receivables for underlifting which have been reclassified as other assets in application of the
sales method.
(**) Compared to the values presented in the balance sheet at December 31, 2017, the item no longer includes financial receivables, which have been reclassified under the new item
“Other current financial assets”.
The adoption of the new requirements resulted in some updates
of the line items presented in the financial statements; in
particular:
-
in the profit and loss account: (i) as a consequence of the
adoption of IFRS 9, an additional line item to present separately
impairment losses/reversals of trade and other receivables
(named “Net (impairment losses) reversals of trade and other
receivables”) was presented; these items were previously
recognised within the line item “Purchases, services and other”.
Consequently, in order to have homogeneous comparative
information, these items referred to the comparative years,
determined in accordance with the superseded IAS 39, were
reclassified into the new line item; and (ii) the line item “Net
(impairments) reversals” was renamed as “Net (impairment
losses) reversals of tangible and intangible assets”;
in the statement of comprehensive income (loss) an additional line
item aimed to present subsequent change of minor investments
measured at fair value with effects recognised in OCI was presented
within items that may not be reclassified subsequently to the profit
and loss account.
-
Furthermore, the following changes have been made in the balance sheet:
- the current financing receivables were reclassified out of the line
item “Trade and other receivables” into the new line item “Other
current financial assets”, both in the current and comparative
year; this new presentation of the balance sheet was aimed,
essentially, to present separately the trade and other exposures
from the financial ones, being characterised by different
originations, risk profiles and evaluation processes;
- the breakdown of the items of Eni shareholders’ equity was
updated to present separately the related most relevant items.
4 | IFRSs not yet effective
IFRSs ISSUED BY THE IASB AND ADOPTED BY THE EU
By the Commission Regulation No. 2017/1986 issued by the
European Commission on October 31, 2017, IFRS 16 “Leases”
(hereinafter IFRS 16), which replaces IAS 17 and related
interpretations, was adopted. In particular, IFRS 16 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.
The new IFRS eliminates the classification of leases as either
operating leases or finance leases for the preparation of lessees’
-
-
financial statements; in particular, for all leases that have a lease
term of more than 12 months, it is required:
-
in the balance sheet, to recognise a right-of-use asset, that
represents a lessee’s right to use an underlying asset (hereinafter
also RoU asset), and a lease liability, that represents the lessee’s
obligation to make the contractual lease payments; as allowed by
the standard, the right-of-use assets and the lease liabilities are
presented separately from other assets and other liabilities;
in the profit and loss account, to recognise, within operating
costs, the depreciation charges of the right-of-use asset and,
within finance expense, the interest expense on the lease liability,
if not capitalised, rather than recognising the operating lease
payments within operating costs under IAS 17, effective until year
2018. The depreciation charges of the right-of-use asset and the
interest expense 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
will include: (i) the lease expenses relating to short-term leases
or leases of low-value assets, as allowed under the simplified
approach provided for by IFRS 16; and (ii) the variable lease
payments that are not included in the measurement of the lease
liability (e.g., payments based on the use of the underlying asset);
in the statement of cash flows, to recognise cash payments for
the principal portion of the lease liability within the net cash used
in financing activities and interest expenses within the net cash
provided by operating activities, if they are recognised in the profit
and loss account, or within the net cash used in investing activities
if they are capitalised as referred to 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 will result in a significant impact in the statement of cash
flows, by determining: (a) an improvement of the net cash provided
by operating activities, which will no longer include the operating lease
payments, not capitalised, but will only include the cash payments for
the interest portion of the lease liability that are not capitalised27; (b)
an improvement of the net cash used in investing activities, which will
no longer include capitalised lease payments for property, plant and
equipment and intangible assets, but will only include cash payments
for the capitalised interest portion of the lease liability; and (c) a
worsening in the net cash used in financing activities, which will include
cash payments for the principal portion of the lease liability.
(27) The net cash provided by operating activities will include also: (i) the short-term lease payments and payments for leases of low-value assets; and (ii) variable lease payments not included in the
measurement of the lease liability.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018
162
Conversely, a lessor continues to classify its leases as either operating
leases or finance leases. IFRS 16 enhances disclosures both for
lessees and for lessors. IFRS 16 shall be applied for annual reporting
periods beginning on or after January 1, 2019.
In 2018, the Group completed the analytical activities aimed to identify
the areas affected by the adoption of the new requirements, update
the processes and systems and assess the expected impacts on the
Consolidated Financial Statements.
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 lands, service stations for the sale of oil products, as well as 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.
In the Exploration & Production segment, the activities are often
carried out through unincorporated joint operations, managed by
one of the partners (the operator), which has the responsibility to
carry out the operations and the approved work programmes. The
operator usually enters into a contract (including lease contracts),
as the sole signatory, for the activities of the unincorporated joint
operation. Accordingly, the operator manages the leases, makes
lease payments to the lessor and recharges the costs to the other
partners (the so-called followers) proportionally. On this regard,
the indications of the IFRS Interpretations Committee (hereinafter
also the IFRIC) issued in September 2018 applies. In particular, the
IFRIC indicated that, 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 shall recognise in the balance sheet: (i) the entire
lease liability and (ii) the entire RoU asset, unless there is a sublease
with the followers. On the other hand, if the lease contract is signed
by all the partners, Eni shall recognise its share of the RoU asset
and lease liability based on its working interest. If Eni does not have
primary responsibility for the lease liability, it does not recognise
any RoU asset or lease liability related to the lease contract. The
followers’ share of the RoU asset, recognised by the operator, will
be recovered according to the joint operation’s 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. The IFRIC indications have been confirmed
at its March 2019 meeting.
The complexity of the contracts, as well as their multiannual duration,
has required a complex judgement by management to determine the
assumptions to be applied in order to estimate the expected impacts
deriving from the adoption of the new requirements. In particular, the
main assumptions were the following ones:
- for lease contracts related to assets used in the Oil & Gas operations
(mainly drilling rigs and FPSOs) set out as operator of the Oil &
Gas activities, the recognition of 100% of the lease liability and
the right-of-use asset in line with the indications provided by the
IFRIC. When the lease contracts are set out by companies, other
than subsidiaries, that act as operators on behalf of the other
participating companies (the so-called operating companies),
consistently with the provision to recover from the followers the
costs related to the Oil & Gas activities, the participating companies
recognise their shares of the right-of-use assets and the lease
liabilities based on their working interest, considering any available
information on the expected use of the underlying assets;
- the separation of non-lease components, also on the basis of
in-depth analyses performed with external experts, with reference
to the main contracts related to the upstream activities (drilling
rigs) which provide for single payments relating to both lease and
non-lease components;
- the assessment of extension or termination options in order to
determine the lease term;
- the identification of variable lease payments and their
characteristics in order to establish whether or not28 they shall be
included in the measurement of the lease liability and the right-of-
use asset;
- the discount rate used to measure the lease liability that is the
lessee’s incremental borrowing rate. This rate have been defined
considering the lease term of the lease contracts, the currencies
and the characteristics of the lessees’ economic environment,
defined on the basis of the country risk premium assigned to each
Country where Eni operates.
On initial application, Eni elects to apply the following practical
expedients allowed by the accounting standard:
- possibility to adopt the modified retrospective approach, by
recognising the cumulative effect of initially applying the new
standard as an adjustment to the opening balance at January 1,
2019, without restating the comparative information;
- possibility not to 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
the 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 the lease
liability, adjusted, if necessary, by any prepaid amounts already
recognised in the balance sheet;
- as an alternative to performing an impairment review, possibility
to adjust the right-of-use assets, existing at January 1, 2019,
by the amount of any provision for onerous lease contracts
recognised at December 31, 2018;
- upon transition, election not to consider leases for which the lease
term ends within 12 months of January 1, 2019 as short-term leases.
Based on the available information, the adoption of IFRS 16
results in the recognition of right-of-use assets for €5.7 billion
and lease liabilities for €5.8 billion; the estimated amount of the
lease liabilities includes the payables for lease fees outstanding
at January 1, 2019, previously classified as trade payables. The
estimated impacts of the initial adoption of IFRS 16 might be
(28) Under IFRS 16, variable lease payments linked to future sales or use of an underlying asset are recognised in the profit and loss account and so they are not included in the measurement of the lease
liability/right-of-use asset.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 163
subject to change due to any evolution in the interpretations
deriving, among others, from further IFRIC indications, as well as
due to the development of the data process upon initial adoption of
the standard in the 2019 financial reports. Moreover, the estimated
amount of the lease liabilities includes the share of the lease
liabilities corresponding to the followers’ working interest for €2.0
billion, while the Eni working interest is €3.8 billion.
Based on the currently available information, a reconciliation
between the amount of future minimum lease payments under
non-cancellable operating leases at December 31, 2018 and
the opening balance of the lease liability 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
By the Commission Regulation No. 2018/1595 issued by the
European Commission on October 23, 2018, IFRIC 23 “Uncertainty
over Income Tax Treatments” (hereinafter IFRIC 23) was adopted.
IFRIC 23 clarifies the accounting for (current and/or deferred) tax
assets and liabilities when there is uncertainty over income tax
treatments. IFRIC 23 shall be applied for annual reporting periods
beginning on or after January 1, 2019.
By the Commission Regulation No. 2019/237 issued by the European
Commission on February 8, 2019, the amendments to IAS 28 “Long-
term Interests in Associates and Joint Ventures” (hereinafter the
amendments to IAS 28) were adopted. The amendments to IAS 28 clarify
that entities account for long-term interests in an associate or joint
venture, that, in substance, form part of the entity’s net investment in
the investee and for which settlement is neither planned nor likely to
occur in the foreseeable future, using the provisions of IFRS 9, including
those related to impairment. The amendments to IAS 28 shall be applied
for annual reporting periods beginning on or after January 1, 2019.
By the Commission Regulation No. 2019/402 issued by the
European Commission on March 13, 2019, the amendments to IAS
19 “Plan Amendment, Curtailment or Settlement” (hereinafter the
amendments to IAS 19) were adopted. The amendments to IAS 19
require to use updated actuarial assumptions to determine current
service cost and net interest, when an amendment, curtailment or
settlement to an existing defined benefit pension plan takes place,
for the remainder reporting period after the change of the plan. The
amendments to IAS 19 shall be applied for annual reporting periods
beginning on or after January 1, 2019.
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 March 29, 2018, the IASB issued the document “Amendments
to References to the Conceptual Framework in IFRS Standards”,
which 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. The amendments to the standards shall be applied for annual
reporting periods beginning on or after January 1, 2020.
On October 22, 2018, the IASB issued the 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 October 31, 2018, the IASB issued the amendments to IAS 1 and
IAS 8 “Definition of Material” (hereinafter the amendments to IAS 1
and IAS 8), which 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.
On December 12, 2017, the IASB issued the document “Annual
Improvements to IFRS Standards 2015-2017 Cycle”, which includes,
basically, technical and editorial changes to existing standards. The
amendments to the standards shall be applied for annual reporting
periods beginning on or after January 1, 2019.
Eni is currently reviewing the IFRSs not yet effective in order to
determine the likely impact on the Consolidated Financial Statements.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 164
5 | Cash and cash equivalents
Cash and cash equivalents of €10,836 million (€7,363 million at
December 31, 2017) included financial assets with maturity generally of
up to three months at the date of inception amounting to €8,732 million
(€5,591 million at December 31, 2017) and mainly included short-term
deposits with financial institutions having notice of more than 48 hours.
Cash and cash equivalents consist essentially of bank deposits in euro
and US dollars as a way to employ the Group cash on hand with a view of
funding the Group’s short-term financing needs.
The average maturity of bank deposits in euro of €7,653 million was 29
days and the interest rate of return was a negative 0.29%; the average
maturity of bank deposits in US dollars of €1,074 million was 12 days
with an internal rate of return of 2.59%.
6 | Financial assets held for trading
(€ million)
Quoted bonds issued by sovereign states
Other
December 31, 2018
1,083
5,469
6,552
December 31, 2017
1,022
4,990
6,012
From January 1, 2018, financial assets held by the Group captive
insurance company Insurance DAC of €207 million, previously
classified as available for sale, have been classified as held for trading
in accordance to the provisions of IFRS 9 on the base of the conditions
existing at the adoption date.
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 of Eni SpA include securities subject
to lending agreements of €1,301 million (€845 million at December
31, 2017).
The breakdown by currency is provided below:
(€ million)
Euro
US dollars
Other currencies
December 31, 2018
4,573
1,614
365
6,552
December 31, 2017
4,232
1,025
755
6,012
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
The breakdown by issuing entity and credit rating is presented below:
Quoted bonds issued by sovereign states
Fixed rate bonds
Italy
Other(*)
Floating rate bonds
Italy
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
Floating rate bonds
Quoted bonds issued by financial and insurance companies
Quoted bonds issued by industrial companies
Other
Total other bonds
Total other financial assets held for trading
(*) Individual amounts included herein are lower than €50 million.
165
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The fair value hierarchy is level 1 for €6,362 million and level 2 for €190 million. During 2018, there were no transfers between the different
hierarchy levels of fair value.
7 | Trade and other receivables
As of January 1, 2018, the effects of the application of IFRS 9 and IFRS 15 are the following:
(€ million)
Amount as of 31 December 2017
Changes in accounting policies (IFRS 9)
Changes in accounting policies (IFRS 15)
Reclassification to other current asssets (IFRS 15)
Amount as of 1 January 2018
Trade and other
receivables
15,421
(427)
(372)
(466)
14,156
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018
166
The adoption of IFRS 9 determined an increase in the provision for doubtful
accounts of €427 million in application of the expected loss model.
The application of IFRS 15 determined a decrease in Other receivables
for €372 million due to the fact that Eni now adopts the sales method
versus the entitlement method previously adopted under the previous
accounting policy as disclosed in note 3 – Changes in accounting policies.
In applying IFRS 15, €466 million of assets related to lifting imbalances
accounted for using the sales method have been reclassified to other
current assets.
More information about the application of IFRS 9 and IFRS 15 is disclosed
in note 3 – Changes in accounting policies.
The following is the analysis of trade and other receivables:
(€ million)
Trade receivables
Receivables from divestments
Receivables from joint operators in E&P activities
Other receivables
December 31, 2018
9,520
122
3,024
1,435
14,101
December 31, 2017
10,182
597
3,369
1,273
15,421
Generally, trade receivables do not bear interest and provide payment
terms within 180 days.
Trade receivables decreased by €662 million, of which €641 million
related to the Gas & Power segment.
At December 31, 2018, Eni sold without recourse trade receivables due
in 2019 for €1,769 million (€2,051 million at December 31, 2017 due in
2018). Derecognized receivables related to the Gas & Power segment
for €1,419 million and to the Refining & Marketing and Chemicals
segment for €350 million.
Receivables from divestments decreased by €475 million due to: (i)
the collection of the price installments related the sale of 10% and
30% interests in the Zohr asset in Egypt made in 2017 respectively
to BP and Rosneft for a total amount of €433 million. An additional
installment relating to the transaction with BP will be collected in June
2019 (€119 million); (ii) the collection for €153 million of the third and
last instalment of a receivable on the divestment of a 1.71% interest in
the Kashagan project to the local partner KazMunayGas.
Amounts receivable from operators in exploration and production
projects included amounts owed by partners in Nigeria for
€977 million (€1,507 million at December 31, 2017). This latter
comprised an amount of €681 million in large part overdue (€713
million at December 31, 2017) owed by the Nigerian national
oil company NNPC in respect of the contractual recovery of the
expenditures incurred at certain projects operated by Eni. During
the year, the Company recovered €140 million of the overdue
amount due to the implementation of the “Repayment Agreement”
agreed with the counterparty, 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. The overdue receivables are
stated net of a discount factor. In addition, a receivable relating
to the recovery of a disputed amount of expenditures due to the
same counterpart was completely written down (€153 million at
December 31, 2017).
Receivables from others comprised the recoverable value amounting
to €300 million 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 in 2016 and in 2018. The two shareholders
purchased those receivables from the venture. The proceeds
from the sale were utilized to reimburse part of the financing loan
provided by the same shareholders to fund the development of the
gas project reserves. The recoverable amount of those receivables
was estimated considering the lifetime expected credit losses which
were evaluated based on a financial model built around empirical
evidence and outcomes from a thorough review of sovereign defaults.
Risks associated with the complex financial outlook of the Country
and the deteriorated operating environment were appreciated in the
recoverability estimation by assuming a deferral in the timing of
collection of future revenues and overdue credit amounts.
Trade and other receivables stated in euro and US dollars amounted to
€7,100 million and €6,119 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, 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
2,454
1,292
1,494
5,240
(9)
5,231
0.2
3,585
157
77
3,819
(3)
3,816
0.1
1,152
672
156
1,980
(44)
1,936
2.6
1,350
2,217
271
3,838
(2,237)
1,601
62.5
2,374
2,374
(857)
1,517
36.1
Total
8,541
4,338
4,372
17,251
(3,150)
14,101
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
167
Eni has classified its business customers and the associated
commercial or industrial exposures based on an individual assessment
of the credit and the counterparty risks. Business customers other
than National Oil Companies (NOC) and public administrations, each
of whom has undergone an individual credit evaluation, have 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
factor of 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
function 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 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
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 factors. 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 restructuring of sovereign debts considering the specificities of
trading relationships with energy companies.
Customers of Eni gas e luce have been 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 Eni gas e luce was assessed on the basis of a provision
matrix as follows:
(€ million)
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
575
449
207
1,231
(20)
1,211
1.6
49
43
2
94
(18)
76
19.1
34
13
1
48
(18)
30
37.5
64
29
2
95
(56)
39
58.9
554
349
3
906
(745)
161
82.2
Total
1,276
883
215
2,374
(857)
1,517
36.1
Trade and other receivables are stated net of the valuation allowance
for doubtful accounts which has been determined considering the
counterparty risk mitigation factors amounting to €3,072 million:
(€ million)
Carrying amount at December 31, 2017
Changes in accounting policies (IFRS 9)
Carrying amount at January 1, 2018
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 at December 31, 2018
Carrying amount at December 31, 2016
Additions
Deductions
Other changes
Carrying amount at December 31, 2017
Trade and other
receivables
2,639
427
3,066
126
372
(189)
(532)
307
3,150
2,303
927
(454)
(137)
2,639
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018
168
Additions to allowance for doubtful accounts on trade and other
performing receivables related for €108 million to the Gas & Power
segment, particularly in the retail business.
Additions to allowance for doubtful accounts on trade and other
defaulted receivables related for €291 million to the Exploration
& Production segment and in connection with receivables for the
supply of equity hydrocarbons to State-owned companies and
other commercial partners.
Utilizations of allowance for doubtful accounts on trade and other
performing and defaulted receivables amounted to €721 million
and mainly related to the Gas & Power segment for €613 million,
in particular utilizations against charges of €579 million 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.
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
Reversal of unutilized provisions
2018
(498)
(37)
120
(415)
The following is the analysis of the 2017 ageing of trade and other
receivables stated according to the valuation criteria in force before
the application of IFRS 9 “Financial instruments”:
(€ million)
Neither impaired nor past due
Impaired (net of the valuation for doubtful accounts)
Not impaired and past due:
- within 90 days
- from 3 to 6 months
- from 6 to 12 months
- over 12 months
December 31, 2017
Trade
receivables
Other
receivables
8,800
567
478
46
147
144
815
10,182
4,604
31
21
9
202
372
604
5,239
Because of the short-term maturity and conditions of remuneration
of trade and other receivables, the fair value approximated the
carrying amount.
Receivables with related parties are disclosed in note 36 –
Transactions with related parties.
8 | Non-current and current inventories
(€ million)
Raw and auxiliary materials and consumables
Materials and supplies
Finished products and goods
Certificates and emission rights
December 31, 2018
889
1,451
2,274
37
4,651
December 31, 2017
999
1,566
2,000
56
4,621
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 €1,334 million (€1,441 million at December 31, 2017).
Finished products and goods included gas and petroleum products for
€1,543 million (€1,287 million at December 31, 2017) and chemical
products for €547 million (€489 million at December 31, 2017).
Certificates and emission rights are measured at the fair value. The fair
value hierarchy is level 1.
Inventories of €95 million (€86 million at December 31, 2017) were
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
169
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 a write down provision of €578 million
(€245 million at December 31, 2017). Net additions to write down
provision for 2018 amounted to €337 million and primarily related
to the alignment of the carrying amount of crude oil and oil products
inventories to their net realizable values at the period end, as a
consequence of the rapid decline in hydrocarbons prices recorded in
the final months of 2018.
Inventories held for compliance purposes of €1,217 million (€1,283
million at December 31, 2017) primarily related to Italian subsidiaries
for €1,200 million (€1,267 million at December 31, 2017) in
accordance with minimum stock requirements for oil and petroleum
products set forth by applicable laws.
9 | Current income tax receivables and payables
(€ million)
Income taxes
Other taxes and duties
December 31, 2018
December 31, 2017
Receivables
191
561
752
Payables
440
1,432
1,872
Receivables
191
729
920
Payables
472
1,472
1,944
Income taxes are described in note 32 – Income tax expense.
Receivables for other taxes and duties included VAT credits for €383 million
(€452 million at December 31, 2017) in relation to down payments by
Italian subsidiaries made in December.
Payables for other taxes and duties consisted of excise and custom duties
of €636 million (€824 million at December 31, 2017).
10 | Other assets
(€ million)
Fair value of derivative financial instruments
Other current assets
December 31, 2018
Current
1,594
664
2,258
Non-current
68
724
792
December 31, 2017
Current
1,231
342
1,573
Non-current
80
1,243
1,323
The fair value related to derivative financial instruments is disclosed
in note 23 – Derivative financial instruments.
The increase in other assets of €322 million included the
reclassification as of January 1, 2018, from the item Trade and other
receivables of the underlifting imbalances related to the Exploration
& Production segment for €466 million following the adoption of the
sales method in application of IFRS 15.
Other assets include: (i) non-current tax assets for € 422 million
(€507 million at December 31, 2017); (ii) 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 €26
million (€119 million at 31 December 2017); (iii) non-current
receivables from others for €35 million (€44 million at December
31, 2017); (iv) non-current receivables for investing activities for €9
million (€118 million at December 31, 2017).
Transactions with related parties are described in note 36 –
Transactions with related parties.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 170
11 | Property, plant and equipment
(€ million)
2018
Net carrying amount - beginning of the year
Additions
Depreciation
Reversals
Impairments
Write-off
Disposals
Currency translation differences
Decrease through loss of control of subsidiary
Transfers
Other changes
Net carrying amount - end of the year
Gross carrying amount - end of the year
Provisions for depreciation and impairments
2017
Net carrying amount - beginning of the year
Additions
Depreciation
Reversals
Impairments
Write-off
Disposals
Currency translation differences
Transfers
Other changes
Net carrying amount - end of the year
Gross carrying amount - end of the year
Provisions for depreciation and impairments
s
g
n
i
d
l
i
u
b
d
n
a
d
n
a
L
1,313
18
(65)
41
(61)
(2)
2
1
81
(54)
1,274
4,060
2,786
1,258
22
(71)
5
(2)
(15)
(5)
84
37
1,313
4,061
2,748
t
n
a
l
p
,
s
l
l
e
w
P
&
E
y
r
e
n
i
h
c
a
m
d
n
a
45,782
432
(6,012)
299
(477)
(12)
(400)
1,623
(4,388)
6,795
(786)
42,856
135,467
92,611
47,090
42
(6,583)
608
(491)
(3)
3
(5,155)
9,940
331
45,782
137,223
91,441
d
n
a
t
n
a
l
p
r
e
h
t
O
y
r
e
n
i
h
c
a
m
3,877
173
(529)
86
(73)
(1)
(9)
36
32
461
(152)
3,901
27,516
23,615
3,789
190
(545)
273
(83)
(2)
(6)
(143)
629
(225)
3,877
26,746
22,869
l
a
s
i
a
r
p
p
a
d
n
a
s
t
e
s
s
a
n
o
i
t
a
r
o
l
p
x
e
P
&
E
s
t
e
s
s
a
e
l
b
i
g
n
a
t
P
&
E
s
s
e
r
g
o
r
p
n
i
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
1,371
330
9,469
6,947
(66)
(32)
53
(58)
(294)
(37)
1,267
1,267
1,905
351
(232)
(193)
(265)
(195)
1,371
1,371
(548)
(4)
(198)
385
(474)
(6,501)
119
9,195
12,559
3,364
15,135
7,302
169
(146)
(2)
(1,376)
(1,527)
(9,673)
(413)
9,469
12,315
2,846
1,346
878
(117)
(1)
2
(1)
10
(542)
234
1,809
2,415
606
1,616
583
(126)
(54)
(2)
(715)
44
1,346
2,061
715
l
a
t
o
T
63,158
8,778
(6,606)
426
(1,276)
(84)
(639)
2,098
(4,877)
(676)
60,302
183,284
122,982
70,793
8,490
(7,199)
1,055
(848)
(239)
(1,448)
(7,025)
(421)
63,158
183,777
120,619
Capital expenditures included capitalized finance expenses of €52 million
(€72 million in 2017) related to the Exploration & Production segment
(€37 million). The interest rate used for capitalizing finance expense
ranged from 2.3% to 2.4% (1.6% to 2.7% at December 31, 2017).
Capital expenditures primarily related to the Exploration & Production
segment for €7,757 million (€7,638 million in 2017) and included the
consideration paid for the award of the interests in the already producing
Concession Agreements of Umm Shaif and Nasr (10%) and Lower Zakum
(5%) and the Concession Agreement of Gasha (25%) under development,
located in the offshore of Abu Dhabi (United Arab Emirates). The price paid
of €869 million was allocated to proved mineral interest (E&P wells, plant
and machinery) for €382 million and to unproved mineral interest for
(E&P tangible assets in progress) €487 million.
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
2 - 17
2 - 12
5
6 - 12
5 - 25
10 - 20
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
171
The criteria adopted by Eni for determining net (impairments)
reversals is reported in note 13 – Net reversal (impairment) of
tangible and intangible assets.
Disposals related to a 10% interest in the Zohr asset in Egypt to
Mubadala Petroleum Llc with a gain of €418 million.
Foreign currency translation differences primarily related to subsidiaries
which utilize the US dollar as functional currency (€2,209 million).
Property, plant and equipment decreased by €4,800 million due to
the exclusion from the consolidation of the assets of the former Eni’s
subsidiary Eni Norge AS which was merged with Point Resources
AS, fully-owned by HitecVision AS, to establish the equity-accounted
joint venture Vår Energi AS, jointly controlled by Eni (69.60%) and
HitecVision AS, with the initial recognition among equity-accounted
investments of Eni’s interest in the combined entity.
Transfers from E&P tangible assets in progress to E&P wells, plant and
machinery related for €2,750 million to progress in the development of
reserves at large projects, comprising Zohr, Jangkrik, East Hub, Noroos
and OCTP projects.
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
€297 million; (ii) the write-off of exploration wells for €66 million due
to the negative outcome of exploration and appraisal activities, mainly
relating to two offshore projects in Morocco and Vietnam.
Other changes included a downward revision of estimates of the
decommissioning provision of the Exploration & Production segment
(negative for €503 million) due to increased discount rates curve,
especially for the US dollar.
Exploration and appraisal activities related for €1,101 million to costs
of suspended exploration wells pending final determination and for
€166 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 period
Increases for which is ongoing the determination of proved reserves
Amounts previously capitalized and expensed in the period
Reclassification to successful exploratory wells following the estimation of proved reserves
Disposals
Decrease through loss of control of subsidiary
Reclassification to assets held for sale
Currency translation differences
Costs for exploratory wells suspended - end of the period
2018
1,263
235
(61)
(297)
(6)
(58)
(24)
49
1,101
2017
1,684
451
(217)
(278)
(199)
(178)
1,263
2016
1,737
282
(109)
(276)
50
1,684
The following information relates to the stratification of the suspended wells pending final determination (ageing):
Costs capitalized and suspended for
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
2018
2017
2016
(€ million)
(number of wells
in Eni’s interest)
(€ million)
(number of wells
in Eni’s interest)
(€ million)
(number of wells
in Eni’s interest)
111
87
903
1,101
111
217
773
1,101
7.02
2.88
24.20
34.10
7.02
4.66
22.42
34.10
222
241
800
1,263
148
261
854
1,263
7.95
3.87
21.44
33.26
5.88
4.69
22.69
33.26
16
609
1,059
1,684
9
251
1,424
1,684
1.05
10.25
21.55
32.85
0.55
3.51
28.79
32.85
Unproved mineral interests include the purchase price allocated to unproved reserves following business combinations or acquisition of
individual properties.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018
172
Unproved mineral interests were as follows:
(€ million)
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
2017
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
1,162
26
(429)
(32)
42
769
a
i
r
e
g
i
N
825
56
40
921
n
a
t
s
i
n
e
m
k
r
u
T
192
(76)
(44)
5
77
A
S
U
99
4
103
1,254
938
138
113
72
(7)
(157)
1,162
(113)
825
75
(21)
192
(14)
99
a
i
r
e
g
l
A
105
(32)
4
77
112
(7)
105
t
p
y
g
E
7
23
(2)
1
29
7
7
b
a
r
A
d
e
t
i
n
U
s
e
t
a
r
i
m
E
487
15
502
l
a
t
o
T
2,390
592
(505)
(110)
111
2,478
2,450
112
147
(7)
(312)
2,390
Unproved mineral interest comprised a property denominated Oil
Prospecting License 245 (“OPL 245”), located in the offshore of
Nigeria, with a net book value of €857 million, which corresponded to
the price paid to the Nigerian Government to acquire a 50% interest in
the property, with the partner Shell acquiring the remaining 50%. As
of December 31, 2018, the net book value of the property was €1,159
million, including capitalized exploration costs 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.
Additions for the year related to the acquisition of unproved reserves as
part of the deals to acquire interests in Oil & Gas assets in production/
development phase in the offshore of Abu Dhabi (United Arab Emirates),
the extension of the concession terms in Nigeria and Egypt and
contractual revisions in Congo.
Accumulated provisions for impairments amounted to €16,471
million (€16,005 million at December 31, 2017).
At December 31, 2018, Eni pledged property, plant and equipment for
€24 million primarily as collateral against certain borrowings (same
amount as of December 31, 2017).
Government grants recorded as a decrease of property, plant and
equipment amounted to €125 million (€110 million at December 31, 2017).
Assets acquired under financial lease agreements amounted to €46
million (€29 million at December 31, 2017).
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.
Property, plant and equipment by segment are described in note 35
– Segment information and information by geographical area.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
12 | Intangible assets
(€ million)
2018
Net carrying amount - beginning of the year
Changes in accounting policies (IFRS 9 and 15)
Net carrying amount restated - beginning of the year
Additions
Amortization
Impairments
Write-off
Currency translation differences
Change through loss of control of subsidiary
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
2017
Net carrying amount - beginning of the year
Additions
Amortization
Reversals
Impairments
Write-off
Currency translation differences
Other changes
Net carrying amount - end of the year
Gross carrying amount - end of the year
Provisions for amortization and impairment
173
s
t
h
g
i
r
n
o
i
t
a
r
o
l
p
x
E
995
995
133
(71)
(15)
39
1,081
1,686
605
1,092
91
(65)
32
(14)
(24)
(115)
(2)
995
1,504
509
s
t
n
e
t
a
p
l
a
i
r
t
s
u
d
n
I
l
a
u
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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
240
240
28
(87)
40
221
1,534
1,313
259
17
(84)
(1)
49
240
1,466
1,226
e
l
b
i
g
n
a
t
n
i
r
e
h
t
O
s
t
e
s
s
a
486
87
573
180
(226)
(16)
(1)
74
584
4,188
3,604
598
83
(137)
(2)
(56)
486
3,778
3,292
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
1,721
87
1,808
341
(384)
(16)
(16)
39
74
40
1,886
7,408
5,522
1,949
191
(286)
32
(14)
(24)
(118)
(9)
1,721
6,748
5,027
l
l
i
w
d
o
o
G
1,204
1,204
8
46
26
1,284
1,320
(23)
(93)
1,204
l
a
t
o
T
2,925
87
3,012
341
(384)
(16)
(16)
47
120
66
3,170
3,269
191
(286)
32
(14)
(24)
(141)
(102)
2,925
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 exploratory 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 in United Arab Emirates,
United States and Mexico.
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, 2018
357
684
40
1,081
December 31, 2017
403
586
6
995
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 €166 million; (ii) concessions,
licenses, trademarks and similar items for €151 million comprised
transmission rights for natural gas imported from Algeria of €27
million; (iii) capital expenditures in progress on natural gas pipelines
for which Eni has acquired transport rights for €78 million (same
amount as of December 31, 2017).
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018
174
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
UOP - 33
3
3 - 33
20 - 33
25 - 33
4 - 20
The carrying amount of goodwill at the end of the year amounted to
€2,422 million, net of cumulative impairments charges.
A breakdown of the stated goodwill by operating segment is provided
below:
(€ million)
Gas & Power
Exploration & Production
Refining & Marketing
Other activities
December 31, 2018
977
187
119
1
1,284
December 31, 2017
932
179
93
1,204
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
European gas market
December 31, 2018
835
142
977
December 31, 2017
835
97
932
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 any
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 the perpetuity of
the last year of the plan to determine the terminal value 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
5.4% for Italy. Post-tax cash flows and discount rates were adopted
as they resulted in an assessment that substantially approximated a
pre-tax assessment.
The excess of the recoverable amount of the CGU Domestic gas market
over its carrying amount including the allocated portion of goodwill
(headroom) amounting to €1,701 million would be reduced to zero
under each of the following alternative hypothesis: (i) a decrease of
63% on average in the projected volumes or commercial margins; (ii)
an increase of 12.1 percentage points in the discount rate; and (iii) a
final negative nominal growth rate of 26.2%.
Goodwill allocated to the CGU European gas market increased by
€45 million following the acquisition 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 residual
amount of €95 million relates to Eni Gas & Power France SA (former
Altergaz SA). 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 the France
gas market CGU including any allocated goodwill by using a post-tax
WACC adjusted considering a country risk for France of 6.1%, while
the impairment review for the Greek gas market CGU was part of the
acquisition evaluation.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
175
13 | Net reversal (impairment) of tangible and intangible 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.
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, in
addition to the CGUs to which goodwill arisen from business combinations
was allocated, electricity generation plants, international pipelines and
LNG vessels; (iii) in the Refining & Marketing business line, refining plants,
retail networks and assets related to other distribution channels grouped
by Country of operations and type of network (retail outlets located along
ordinary routes and high-ways, wholesale facilities); and (iv) the Chemical
business line has been assessed to be a single CGU.
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, 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 and
the associated projections of operating costs and development
expenditures. The CGUs of the Refining & Marketing business line and
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%. The terminal value of the Chemical business
integrated CGU considers the economic useful lives of the underlying
assets and factors a normalized EBITDA (to reflect the cyclicality of the
sector) defined based on the average contribution margin of the plan.
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.
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 the 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 specific 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.
The framework of impairment indicators of exogenous origin remained
substantially stable compared to the context relating to the assessments
performed in the previous year.
In the final part of 2018, after touching a multi-year high at approximately
85 $/BBL, the Brent crude oil price made a sharp downturn driven by a
slowdown in macroeconomic growth, oversupplies and uncertainties
tied with the trade dispute between USA and China, the Brexit and local
geopolitical crises. In spite of the remarkable correction in oil prices which
declined by more than 20 $/BBL to close the year at approximately 60 $/
BBL, based on the review of market fundamentals in the medium-long
term which remain supportive of continued demand growth, as well
as willingness on part of producers to maintain oil markets in balance
and the market view of financial analysts and industry observers,
management retained a long-term Brent price of 70 $/BBL in real terms
2022, substantially in line with the assumption made in the annual report
2017, on which basis management performed the 2018 assets impairment
review and elaborated financial projections for the four-year plan 2019-
2022. Prices of natural gas in Europe are projected to reach a higher level
than in previous planning assumptions driven by an improved balance
between gas demand and supplies supported by a continuing decline in
continental mature fields production and the phase-out of nuclear and
coal power plants. The SERM benchmark refining margin is projected
unchanged from the previous plan at approximately 5 $/BBL in the long-
term, based on expectations of continuing competitive pressures in Europe
from cheaper products streams imported from USA and Middle East, the
effects of which will be mitigated by enactment of stricter environmental
regulations on the sulphur content of marine fuels effective from 2020.
Projections of margins for the main petrochemicals commodities were
scaled down due to management’s expectations of continued competitive
pressures in European markets from more competitive producers based
in USA and Middle East and a slowdown in end markets. However, the
projections of margins in the petrochemicals business determined only
a modest reduction in the value-in-use of the Company’s petrochemicals
CGU because the impairment review is based on a normalized scenario
which factors in the cyclicality of the industry.
Moreover, although at the balance sheet date the market capitalization of
Eni was about 3% lower than the book value of consolidated net assets,
this tendency registered a significant trend reversal and, at the date of
approval of the Financial Statements by the Board of Directors, the market
capitalization exceeded the book value by about 10%.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 176
The management tested for impairment the totality of the Group’s fixed
assets as provided by the Company’s internal guidelines.
The 2018 WACC of Eni, which is the driver for calculating the post-tax WACC
of the Oil & Gas and refining business CGUs to assess their value-in-use,
recorded an increase 0.5 percentage point to 7.3% compared to 2017. This
increase was driven by the projections of higher risk-free yields that Eni’s
methodology links to ten-year Italian government bonds. The WACC used in
the Gas & Power segment and the Chemical business, subject to separate
valuation compared to the Eni’s assessment, line resulted unchanged from
2017. The post-tax WACC rates for 2018 highlighted a certain dispersion
of values compared to the mean, reflecting large differences in the
country risk premiums which were affected by ongoing developments
in each Country operating environment. The adjusted WACC rates used
for impairment test purposes in 2018 ranged from 6.2% to 16.0% in the
Exploration & Production segment.
In the Exploration & Production segment the Company recorded
impairment losses before taxes for €1,025 million driven by a lower-than-
expected performance at certain oilfields, particularly in Congo and USA, a
deteriorated operating environment of a specific project and alignment to
fair value of assets divested or held for sale in Croatia and Ecuador. These
losses were partially offset by reversals of prior-year impairment losses for
€299 million due to better gas prices in Europe and reduced country risk
premiums in certain locations. The post-tax WACC relating to impairment
losses/reversals of impairments of more than €100 million amounted to
6%, corresponding to pre-tax rates ranging from 6% to 9%.
In the Refining & Marketing business line the Company recorded
impairment losses for €156 million related to the investments of the year
for compliance and stay-in-business related to CGUs fully impaired in prior
years for which profitability expectations have remained unchanged from
the previous-year impairment review.
In the Gas & Power segment the Company recorded a reversals of
impairment losses at a gas transportation asset for €66 million driven by
a lower discount rate adjusted for the country risk. In the power business,
reversals and impairments relating to each individual plant resulted offset.
14 | Investments
EQUITY-ACCOUNTED INVESTMENTS
(€ million)
Carrying amount - beginning of the year
Changes in accounting policies (IFRS 9 and 15)
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
Changes in the scope of consolidation
Currency translation differences
Other changes
Carrying amount - end of the year
n
i
s
t
n
e
m
t
s
e
v
n
I
d
e
t
a
d
i
l
o
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c
n
u
s
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i
t
i
t
n
e
i
n
E
y
b
d
e
l
l
o
r
t
n
o
c
116
116
(33)
8
(5)
(6)
2
13
95
2018
i
s
e
r
u
t
n
e
v
t
n
i
o
J
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
n
i
s
t
n
e
m
t
s
e
v
n
I
l
a
t
o
T
3,511
(37)
3,474
120
(151)
409
(430)
(50)
3,448
81
143
7,044
d
e
t
a
d
i
l
o
s
n
o
c
n
u
s
e
i
t
i
t
n
e
n
E
y
b
d
e
l
l
o
r
t
n
o
c
2017
s
e
r
u
t
n
e
v
t
n
o
J
i
s
e
t
a
i
c
o
s
s
A
l
a
t
o
T
168
168
9
(7)
(32)
2
(13)
(11)
116
2,675
1,197
4,040
2,675
63
49
(340)
(41)
(127)
53
2,332
1,197
444
(462)
66
(6)
(13)
(128)
(35)
1,063
4,040
507
(462)
124
(353)
(86)
2
(268)
7
3,511
Acquisitions and share capital increases mainly related to: (i) the
capital contribution to Coral FLNG SA (€48 million) which is engaged
in the development of a floating production and storage unit of LNG
in natural gas-rich Area 4, offshore Mozambique; (ii) the acquisition
for €42 million of a 33.72% interest in Commonwealth Fusion System
Llc (CFS), a company created as a spin-out of the Massachusetts
Institute of Technology for the development of the technology of
power generation from fusion.
Divestments and reimbursements related to the capital
reimbursement of Angola LNG Ltd for €95 million.
The share of Eni’s profit of equity-accounted entities related for
€353 million to the equity result of Angola LNG Ltd, driven by a
reversal of about €260 million of prior-year impairment losses of
the LNG project. The economics of the project improved due to the
favorable outcome of an arbitration proceeding which established
the settlement of a contract to utilize the re-gasification terminal
of Pascagoula owned by Gulf Energy Ltd, where the fees associated
with the contract were previously discounted in the future cash flow
of the upstream project and of the related downstream activity of
gas marketing. The outcome of the arbitration led to the recognition
of an equivalent expense through loss.
The accounting under the equity method of Saipem SpA resulted in a loss
of €146 million due to the recognition by the investee of restructuring
costs and impairment losses of assets. As of December 31, 2018, the
book value of the investment in Saipem amounting to €1,228 million,
which was aligned to the corresponding share of the net assets of the
investee, exceeded by approximately 22% the fair value represented by
the market capitalization of Saipem share. Considering this impairment
indicator and ongoing uncertainties surrounding a recovery in the
investing cycle of oil companies and competitive pressure in the E&C
sector, management performed an impairment review of the investment
to assess its recoverability based on an internal financial model of future
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
177
cash flows of Saipem estimated based on financial projections made
by the sell-side analysts who cover the Saipem share, 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. At date of approval of the financial statements, the book
value of the investment exceeded by approximately 23% the fair value
represented by the market capitalization.
Share of losses of equity-accounted investments included a loss of
€219 million accounted at the joint ventures with the Venezuelan
state-owned company PDVSA, PetroJunín SA, (Eni’s interest 40%) and
Cardón IV SA (Eni’s interest 50%), which are operating the onshore
heavy-oil Junín field and the Perla gas field, respectively. The loss
was driven by the de-booking of the project’s undeveloped proved
reserves (down by 106 million boe) due to a deteriorated operating
environment, as required by the US SEC rules.
Deduction for dividends related for €24 million to United Gas
Derivatives Co.
Other increases included for €3,498 million the initial recognition of Eni’s
participating interest in the joint venture Vår Energi AS (69.60%), which
was established following the business combination between the former
Eni subsidiary Eni Norge AS and Point Resources AS. The joint venture
will be equity-accounted. The book value of the joint venture equals Eni’s
share of the fair values of the combined net assets.
Net carrying amount of equity-accounted investments related to the
following:
(€ million)
Investments in unconsolidated entities controlled by Eni
Eni BTC Ltd
Other investments(*)
Joint ventures
Vår Energi AS
Saipem SpA
Unión Fenosa Gas SA
Gas Distribution Company of Thessaloniki-Thessaly SA
Cardón IV SA
Lotte Versalis Elastomers Co Ltd
PetroJunín SA
AET - Raffineriebeteiligungsgesellschaft mbH
Other investments(*)
Associates
Angola LNG Ltd
Coral FLNG SA
Novamont SpA
United Gas Derivatives Co
Commonwealth Fusion Systems Llc
Other investments(*)
(*) Each individual amount included herein was lower than €25 million.
December 31, 2018
December 31, 2017
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
137
98
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
49.00
50.00
50.00
40.00
33.33
13.60
25.00
25.00
33.33
33.72
i
g
n
y
r
r
a
c
t
e
N
t
n
u
o
m
a
63
53
116
1,413
350
137
114
210
32
76
2,332
802
54
71
82
54
1,063
3,511
t
n
e
m
t
s
e
v
n
i
e
h
t
f
o
%
100.00
31.00
50.00
49.00
50.00
40.00
33.33
13.60
25.00
25.00
33.33
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 €58 million, related to
Novamont SpA for €43 million and Unión Fenosa Gas SA for €15 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, 2018, the market value of the investments
listed in regulated stock markets was as follows:
(€ million)
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
3.265
1,008
1,228
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018
178
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
December 31, 2018
219
681
900
5
15
(22)
31
(10)
919
December 31, 2017
276
276
3
(19)
(23)
(18)
219
In applying IFRS 9, minor investments were recognized at fair value
resulting in an asset write-up of €681 million as of January 1, 2018.
Those investments in equity instruments were previously accounted for
under IAS 39 which permitted entities to measure unquoted investments
in equity instruments at cost if their fair value could not be determined
reliably. This increase related to: (i) Nigeria LNG Ltd for €511 million
(carrying amount of €99 million at December 31, 2017). The investment
book value as of December 31, 2018 was €651 million net of the
dividends paid in the year; (ii) Saudi European Petrochemical Co “IBN
ZAHR” for €130 million (carrying amount of €13 million at December 31,
2017). The investment book value as at December 31, 2018 was €144
million net of the dividends paid in the year.
The fair value of the main non-controlling interests in unquoted
undertakings, classified within level 3 of the fair value hierarchy, was
estimated based on a methodology that combines expected additional
earnings and sum-of-the-parts measurements (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.
Changes of 1% of the cost of capital considered in the valuation do not
produce significant changes at the fair value evaluation.
Dividends paid by those investments are disclosed in note 31 –
Income (expense) from investments.
Investments in subsidiaries, joint arrangements and associates as
of December 31, 2018 are presented in the annex “List of companies
owned by Eni SpA as of December 31, 2018”. This annex includes also
the changes in the scope of consolidation.
15 | Other financial assets
(€ million)
Long-term financing receivables held for operating purposes
Long-term financing receivables held for operating purposes
Financing receivables held for non-operating purposes
Securities held for operating purposes
Non-current
1,189
December 31, 2018
Current
61
51
112
188
300
1,189
1,189
64
1,253
Non-current
1,602
December 31, 2017
Current
23
84
107
209
316
1,602
1,602
73
1,675
316
Financing receivables are stated net of allowance for doubtful accounts as follows:
300
(€ million)
Carrying amount at December 31, 2017
Additions
Deductions
Currency translation differences
Carrying amount at December 31, 2018
Allowance for
doubtful accounts
of financing receivables
730
279
(596)
17
430
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
179
Financing receivables held for operating purposes of €1,301 million
(€1,709 million at December 31, 2017) related principally to funds
provided to joint ventures and associates in the Exploration &
Production segment (€1,075 million) and the Gas & Power segment
(€103 million). 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 €705 million at December 31,
2018 (€955 million at December 31, 2017). The recoverability of those
assets was assessed considering the performance of the industrial
initiatives financed, in addition to other factors.
Financing receivables held for operating purposes due beyond five years
amounted to €1,088 million (€1,393 million at December 31, 2017).
The fair value of non-current financing receivables held for operating
purposes of €1,188 million has been estimated based on the present
value of expected future cash flows discounted at rates ranging
from -0.2% to 2.9% (-0.2% and 2.5% at December 31, 2017). This
valuation methodology does not apply to assess the recoverability
of the financial loan granted to the joint venture Cardón IV SA to fund
the development projects carried out by the venture, which can be
assimilated to net capital employed. The recoverability of this financing
loans depends on the future cash flows of the industrial project, which
are exposed to a credit risk given the difficult financial condition of
Venezuela. In assessing the recoverability of the loan, management
carried out an appreciation of the risk to convert in cash the project
future revenues by projecting a deferral in the timing of revenues
collection and discounting the resulting future cash flows at a rate
adjusted for the country risk that factors in the deteriorated operating
environment of the Country. The outcomes of the assessment
confirmed the carrying amount of the financial loan.
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.
Additions to the allowance for doubtful accounts related to a loss taken
at a financing receivable granted to a joint venture in Russia engaged
in the execution of an exploratory project in the Black Sea due to the
unsuccessful outcome of the initiative.
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 €188 million and € 1,299 million, respectively.
Securities held for operating purpose related to listed bonds issued
by sovereign states (listed bonds issued by sovereign states for
€69 million and by the European Investment Bank for €4 million at
December 31, 2017).
Securities for €20 million (same amount as of December 31, 2017)
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
29
8
3
64
e
u
l
a
v
l
i
a
n
m
o
N
)
n
o
i
l
l
i
m
€
(
24
29
8
3
64
e
u
l
a
v
r
i
a
F
)
i
n
o
i
l
i
m
€
(
25
29
8
3
65
e
t
a
r
l
i
a
n
m
o
N
n
r
u
t
e
r
f
o
%
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 4.40
from 2019 to 2025
from 2019 to 2023
Baa3
from Aa3 to Baa1
BBB
from AA to A-
from 2019 to 2020
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 €25 million.
Securities having a maturity within five years amounted to €63 million.
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 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018
180
16 | Trade and other payables
As of January 1, 2018, the effects of the application of IFRS 15 are the following:
(€ million)
Carrying amount at December 31, 2017
Changes in accounting principles (IFRS 15)
Reclassification to other current liabilities (IFRS 15)
Carrying amount at January 1, 2018
Down payments
and advances
from customers
545
(545)
Trade
payables
10,890
10,890
Down payments
and advances
from joint
venture partners
in Exploration &
Production
252
252
Other
payables
5,061
(113)
(785)
4,163
Trade
and other
payables
16,748
(113)
(1,330)
15,305
The application of IFRS 15 determined a decrease in the stated
amount of payables recognized in connection with lifting imbalances
in the Exploration & Production segment for €113 million in
application of the sales method in lieu of the entitlement method.
The reclassification to other current liabilities (IFRS 15) related
to: (i) lifting imbalances of the Exploration & Production segment
recognized by using the sales method for €785 million; (ii) down
payments and advances from customers reclassified as liabilities
from contracts with customers.
More information about the application of IFRS 9 and IFRS 15 is
reported 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 customers
Down payments and advances from partners in Exploration & Production activities
Payables for purchase of non-current assets
Payables due to partners in Exploration & Production activities
Other payables
December 31, 2018
11,645
207
2,530
1,151
1,214
16,747
December 31, 2017
10,890
545
252
2,094
1,968
999
16,748
Trade payables were denominated in euro for €6,484 million and in
US dollar for €9,403 million.
Because of the short-term maturity and conditions of remuneration of
trade payables, the fair values approximated the carrying amounts.
Payables due to related parties are described in note 36 –
Transactions with related parties.
17 | Other liabilities
(€ million)
Fair value of derivatives financial instruments
Liabilities from contracts with customers
Cautionary deposits
Other liabilities
December 31, 2018
Current
1,445
1,108
Non-current
40
518
268
676
1,502
1,427
3,980
December 31, 2017
Current
1,011
Non-current
91
504
1,515
255
1,133
1,479
In applying IFRS 15: (i) liabilities from contracts with customers
included the reclassification as of January 1, 2018, from the item
Trade and other liabilities of down payments and advances from
customers of €545 million; (ii) other current liabilities included the
reclassification as of January 1, 2018, from the item Trade and other
receivables of the lifting imbalances in the Exploration & Production
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
181
segment for €785 million following the adoption of the sales method.
Fair value related to derivative financial instruments is disclosed in
note 23 – Derivative financial instruments and hedge accounting.
Liabilities from contracts with customer of €1,626 million included:
(i) advances denominated in local currency of €716 million relating
to future supplies of equity hydrocarbons to our Egyptian State-
owned partners in relation to the operations of Eni’s Concession
Agreements in the Country for the next four-year period and 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 €66 million;
the non-current portion amounted to €518 million.
Cautionary deposits related to deposits from retail customers for
the supply of gas and electricity of €233 million (€215 million at
December 31, 2017).
Other current liabilities included overlifting imbalances of the
Exploration & Production segment for €1,004 million.
Other non-current liabilities included tax liabilities for €61 million
(€45 million at December 31, 2017) and other debts for €155 million
(€45 million at December 31, 2017).
Transactions with related parties are described in note 36 –
Transactions with related parties.
18 | Financial liabilities
(€ million)
Banks
Ordinary bonds
Convertible bonds
Commercial papers
Other financial institutions
December 31, 2018
December 31, 2017
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
t
b
e
d
m
r
e
t
-
t
r
o
h
S
201
1,664
377
2,242
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
801
1,445
40
2,286
t
b
e
d
m
r
e
t
-
g
n
o
L
3,200
16,520
387
72
20,179
l
a
t
o
T
4,202
17,965
387
1,664
489
24,707
Financial liabilities included an increase of €1,158 million driven
by: (i) new issuances net of repayments made of €320 million;
(ii) currency translation differences relating to companies having
debt denominated in currency other than the functional currency
for €314 million (iii) the de-recognition of Eni Norge AS cash and
cash equivalents for €494 million due to the loss of control on the
former subsidiary, which were deposited at the Group’s financial
companies.
Commercial papers were issued by the Group’s financial
subsidiaries.
The following table reflects long-term debt and current portion of
long-term debt as of December 31, 2018 by maturity:
(€ million)
Banks
Ordinary bonds
Convertible bonds
Other financial institutions
2020
556
2,391
9
2,956
2021
345
921
10
1,276
2022
393
698
390
9
1,490
2023
829
1,858
11
2,698
After
587
11,055
20
11,662
Total
2,710
16,923
390
59
20,082
Eni entered into long-term borrowing facilities with the European
Investment Bank. These borrowing facilities are subject to the
maintenance of a minimum level of credit rating. According to
the agreements, should the Company lose the minimum credit
rating, new guarantees could be required to be agreed upon with
the European Investment Bank. In addition, Eni entered into long
and medium-term facilities subject to the maintenance of certain
financial ratios based on the Consolidated Financial Statements
of Eni with Citibank Europe Plc, whose non-compliance allows the
bank to request an early repayment. At December 31, 2018, debts
subjected to restrictive covenants amounted to €1,337 million
(€1,664 million at December 31, 2017). Eni was in compliance with
those covenants.
Ordinary bonds consisted of bonds issued within the Euro Medium
Term Notes Program for a total of €16,904 million and other bonds
for a total of €2,800 million.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018
182
The following table provides a breakdown of ordinary bonds by issuing entity, maturity date, interest rate and currency as of December 31, 2018:
(€ million)
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 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 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
1,500
1,200
1,000
1,000
1,000
1,000
1,000
900
800
800
750
750
750
700
650
600
335
295
167
1,528
16,725
873
873
393
305
349
2,793
19,518
17
16
38
27
19
9
8
(5)
2
(1)
14
8
5
1
2
(5)
15
4
5
179
2
1
4
1
(1)
7
186
1,517
1,216
1,038
1,027
1,019
1,009
1,008
895
802
799
764
758
755
701
652
595
350
299
167
1,533
16,904
875
874
397
306
348
2,800
19,704
EUR
EUR
EUR
EUR
EUR
EUR
EUR
EUR
EUR
EUR
EUR
EUR
EUR
EUR
EUR
EUR
GBP
EUR
YEN
USD
USD
USD
USD
USD
USD
from
2019
2028
2019
2026
y
t
i
r
u
t
a
M
to
2019
2025
2020
2029
2020
2023
2026
2024
2021
2028
2019
2024
2027
2022
2025
2028
2021
2043
2037
2027
2023
2028
2020
2040
2027
%
e
t
a
R
to
from
4.125
3.750
4.250
3.625
4.000
3.250
1.500
0.625
2.625
1.625
3.750
1.750
1.500
0.750
1.000
1.125
5.000
5.441
2.810
variable
4.000
4.750
4.150
5.700
7.300
4.750
3.875
1.955
As of December 31, 2018, ordinary bonds maturing within 18
months amounted to €4,596 million. During 2018, new bonds
issued amounted to €2,844 million. The following table provides a
breakdown of convertible bonds issued by Eni SpA as of December
31, 2018:
(€ 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
t
n
u
o
m
A
400
(10)
l
a
t
o
T
390
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 issued provides for by 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 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.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
183
Eni has in place a program for the issuance of Euro Medium Term
Notes up to €20 billion, of which €16.7 billion were drawn as of
December 31, 2018.
The following table provides a breakdown by currency of
long-term debt, its current portion and the related weighted
average interest rates:
December 31, 2018
December 31, 2017
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
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
)
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
t
b
e
d
m
r
e
t
t
r
o
h
S
)
n
o
i
l
l
i
m
€
(
904
1,329
9
2,242
f
o
n
o
i
t
r
o
p
m
r
e
t
-
t
r
o
h
S
d
n
a
t
b
e
d
m
r
e
t
g
n
o
L
t
b
e
d
m
r
e
t
-
g
n
o
l
)
n
o
i
l
l
i
m
€
(
20,094
1,694
677
22,465
e
t
a
r
e
g
a
r
e
v
A
)
%
(
0.5
1.8
(0.7)
e
t
a
r
e
g
a
r
e
v
A
)
%
(
2.4
4.8
4.7
Euro
US dollar
Other currencies
Total
As of December 31, 2018, Eni retained undrawn uncommitted
borrowing facilities amounting to €12,484 million (€11,584 million
at December 31, 2017) and undrawn long-term committed borrowing
facilities of €5,214 million (€5,802 million at December 31, 2017).
Those facilities bore interest rates reflecting prevailing conditions on
the marketplace.
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, 2018
20,257
399
3,445
111
24,212
December 31, 2017
19,219
410
4,021
114
23,764
Fair value of financial debt was calculated by discounting the expected
future cash flows at discount rates ranging from -0.2% to 2.9% (-0.2%
and 2.5% at December 31, 2017).
Because of the short-term maturity and conditions of remuneration
of short-term debts, the fair value approximated the carrying amount.
Changes in borrowings are provided below:
(€ million)
Carrying amount at December 31, 2017
Cash flows
Currency translation differences
Changes in the scope of consolidation
Other non-monetary changes
Carrying amount at December 31, 2018
Transactions with related parties are described in note 36 – Transactions with related parties.
t
b
e
d
m
r
e
t
-
g
n
o
L
t
n
e
r
r
u
c
d
n
a
n
o
i
t
r
o
p
t
b
e
d
m
r
e
t
-
g
n
o
l
f
o
22,465
1,033
126
59
23,683
t
b
e
d
m
r
e
t
-
t
r
o
h
S
2,242
(713)
188
494
(29)
2,182
l
a
t
o
T
24,707
320
314
494
30
25,865
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018
184
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. Available-for-sale financial assets
D. Liquidity (A+B+C)
E. Financing receivables
F. Short-term debt towards banks
G. Long-term debt towards banks
H. Bonds
I. Short-term debt towards related parties
L. Other short-term liabilities
M. Other long-term liabilities
N. Total borrowings (F+G+H+I+L+M)
O. Net borrowings (N-D-E)
December 31, 2018
Non-current
2,710
17,313
59
20,082
20,082
Current
10,836
6,552
17,388
188
383
768
2,781
661
1,138
52
5,783
(11,793)
Total
10,836
6,552
17,388
188
383
3,478
20,094
661
1,138
111
25,865
8,289
Current
7,363
6,012
207
13,582
209
201
801
1,445
164
1,877
40
4,528
(9,263)
December 31, 2017
Non-current
3,200
16,907
72
20,179
20,179
Total
7,363
6,012
207
13,582
209
201
4,001
18,352
164
1,877
112
24,707
10,916
Financial assets held for trading are disclosed in note 6 – Financial
assets held for trading.
Current financing receivables are disclosed in note 15 – Other
financial assets.
20 | Provisions for contingencies
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
n
o
i
s
i
v
o
r
P
8,126
(502)
259
(190)
(1,024)
153
(45)
6,777
s
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t
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g
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t
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2,653 1,107
148
299
527
73
205
493
(12)
(287)
(33)
(11)
(14)
2,595
2
(214)
(289)
(1)
34
37
824
(118)
(31)
(8)
17
(20)
440
(481)
110
327
s
e
s
s
o
l
r
o
f
n
o
i
s
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r
P
s
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m
t
s
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v
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i
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o
182
48
(1)
2
(27)
204
L
I
O
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f
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76
51
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60
l
a
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p
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g
n
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r
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t
c
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r
t
s
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r
d
n
a
65
19
(14)
(22)
s
e
v
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t
n
e
c
n
i
y
c
n
a
d
n
u
d
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r
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f
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s
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P
140
9
(17)
(17)
(5)
3
130
(2)
108
(4)
66
38
)
*
(
r
e
h
t
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l
a
t
o
T
306 13,447
1,363
223
(502)
249
(1,443)
(100)
(18)
(389)
(2) (1,051)
210
4
(36)
2
377 11,886
(€ million)
Carrying amount at December 31, 2017
New or increased provisions
Initial recognition and changes in estimates
Accretion discount
Reversal of utilized provisions
Reversal of unutilized provisions
Changes in the scope of consolidation
Currency translation differences
Other changes
Carrying amount at December 31, 2018
(*) Each individual amount included herein was lower than €50 million.
The Group makes full provision for the future costs of
decommissioning oil and natural gas wells, facilities and
related pipelines on a discounted basis upon installation. The
decommissioning provisions, included the discounted 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 €6,266 million. Estimate
revisions of €502 million were driven by an increase in the
discount rate curve in particular for the US dollar. Such increase
was partially offset by the recognition of new decommissioning
obligations due to the activity of the year and upward revisions
of cost estimates. The unwinding of discount recognized
through profit and loss for €259 million was determined based
on discount rates ranging from -0.2% to 6.1% (from -0.01% to
5.98% at December 31, 2017). Main expenditures associated with
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
185
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, 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, 2018,
environmental provision primarily related to Syndial SpA for €2,009
million and to the Refining & Marketing business line for €348 million.
The litigation provision comprised the expected liabilities associated
with legal proceedings and other matters arising from contractual
claims, contract renegotiations, including arbitration, fines and
penalties due to antitrust proceedings and administrative matters.
These provisions represented the Company’s best estimate of the
expected, probable liabilities associated with pending litigation and
commercial disputes and primarily related to the Exploration &
Production segment for €653 million. Utilizations of €503 million
mainly related to the definition of a price revision relating to a gas sale
contract with a long-term buyer, the effect of which was compensated
by the reduction of the receivable due by the gas supplier recognized
in other non-current assets.
Provisions for taxes included the estimated charges that the Company
expects to incur to settle uncertain tax matters and tax claims from
authorities in connection the application of current tax rules at certain
Italian and non-Italian subsidiaries in the Exploration & Production
segment (€397 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 €236 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
€114 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 accrued at the
reporting date because of the effective accident rate occurred in past
reporting periods.
Provisions for redundancy incentives were recognized due to a
restructuring program involving the Italian personnel related to past
reporting periods.
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
Provision for employee benefits
December 31, 2018
275
385
148
808
309
1,117
December 31, 2017
284
409
135
828
194
1,022
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.
Other employee benefit plans related to deferred monetary incentive
plans for €136 million, the isopensione plans of Eni gas e luce SpA for
€132 million, jubilee awards for €22 million, long-term incentive plan still
outstanding for €8 million and other long-term plans for €11 million.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 186
Present value of employee benefits, estimated by applying actuarial techniques, consisted of the following:
December 31, 2018
December 31, 2017
d
e
n
fi
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d
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284
997
135
1,416
194
1,610
298
895
136
1,329
158
1,487
4
1
1
(15)
27
31
(25)
(31)
6
2
1
(35)
(8)
(90)
2
2
13
1
12
1
(9)
29
37
(11)
(30)
19
3
1
(59)
(8)
(90)
1
26
4
31
42
1
30
29
1
71
38
19
3
(6)
(1)
(5)
20
(1)
115
118
1
(133) (10)
(8)
(92)
34
(1)
(74)
(2)
3
24
29
54
(14)
71
(3)
(1)
1
1
(37)
(12)
(15)
59
2
2
(1)
(1)
2
(6)
(1)
26
34
47
(14)
66
(5)
1
1
1
(53)
(12)
(17)
54
1
3
3
28
(36)
(2)
(3)
80
35
50
(14)
69
(5)
29
1
1
(89)
(14)
(20)
1
60
(9)
51
275
925
148
1,348
309
1,657
284
997
135
1,416
194
1,610
588
17
(21)
25
1
24
(26)
(64)
26
545
5
5
385
588
17
(21)
25
1
24
(26)
(64)
26
545
5
5
808
148
588
17
(21)
25
1
24
(26)
(64)
26
545
5
5
1,117
309
619
20
12
24
1
23
(25)
(15)
(47)
588
619
20
12
24
1
23
(25)
(15)
(47)
588
619
20
12
24
1
23
(25)
(15)
(47)
588
284
409
135
828
194
1,022
(€ million)
Present value of benefit liabilities at beginning
of year
Current cost
Interest cost
Remeasurements:
- actuarial (gains) losses due to changes
in demographic assumptions
- 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 asset held for sale
Changes in the scope of consolidation
Currency translation differences
and other changes
Present value of benefit liabilities
at end of year (a)
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)
Net liability recognized at end of year (a-b+c)
275
Employee benefit plans included the liability attributable to partners
operating in exploration and production activities of €181 million
(€177 million at December 31, 2017). Eni recorded a receivable for
an amount equivalent to such liability.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
187
Costs charged to the profit and loss account consisted of the following:
(€ million)
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)”
2017
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
27
2
31
(17)
14
14
43
29
14
24
(1)
29
(20)
9
9
32
23
9
4
4
4
4
4
3
3
3
3
3
2
1
2
2
2
5
3
2
2
2
2
2
2
6
4
2
29
3
37
(17)
20
20
52
32
20
26
1
34
(20)
14
14
41
27
14
42
115
1
1
1
30
188
188
54
28
1
1
1
3
86
86
Total
71
118
38
(17)
21
1
20
30
240
220
20
80
29
35
(20)
15
1
14
3
127
113
14
Costs of defined benefit plans recognized in other comprehensive income consisted of the following:
(€ million)
Remeasurements
Actuarial (gains)/losses due to changes in demographic assumptions
Actuarial (gains)/losses due to changes in financial assumptions
Experience (gains) losses
Return on plan assets
Change in asset ceiling
2018
2017
Italian
defined
benefit
plans
Foreign
defined
benefit
plans
FISDE,
foreign
medical
plans
and other
(31)
6
21
5
1
1
1
1
12
13
Italian
defined
benefit
plans
Foreign
defined
benefit
plans
FISDE,
foreign
medical
plans
and other
(5)
(1)
(14)
71
(3)
(12)
(1)
Total
(14)
66
(5)
(12)
(6)
42
(1)
35
Total
(30)
19
21
5
15
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018
188
Plan assets consisted of the following:
(€ million)
December 31, 2018
Plan assets with
a quoted market price
Plan assets without
a quoted market price
December 31, 2017
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
Assets held
by insurance
company
Other
Total
115
37
238
6
6
37
48
238
329
10
48
329
10
115
16
16
2
2
9
9
56
56
60
60
18
3
21
13
3
16
70
542
3
70
545
100
585
3
100
588
The main actuarial assumptions used in the measurement of the liabilities at year-end and in the estimate of costs expected for 2019
consisted of the following:
(%)
2018
Discount rate
Rate of compensation increase
Rate of price inflation
Life expectations on retirement at age 65
2017
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
long-term
benefit plans
1.5
2.5
1.5
1.5
2.5
1.5
0.8-18.0
1.5-16.5
0.8-16.0
13-25
0.6-15.5
1.5-13.5
0.6-14.8
13-24
1.5
1.5
24
1.5
1.5
24
0.2-1.5
1.5
0.0-1.5
1.5
(years)
(years)
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:
(%)
2018
Discount rate
Rate of compensation increase
Rate of price inflation
Life expectations on retirement at age 65
2017
Discount rate
Rate of compensation increase
Rate of price inflation
Life expectations on retirement at age 65
Euro area
Rest
of Europe
1.5-1.9
1.5-3.0
1.5-2.0
21-22
1.5-1.8
1.5-3.0
1.5-1.9
21-24
0.8-2.9
2.5-3.8
0.8-3.3
23-25
0.6-2.5
2.5-3.7
0.6-3.4
22-24
Africa
3.7-18.0
5.0-16.5
3.7-16.0
13-17
3.7-15.5
5.0-13.5
3.7-14.8
13-17
Other
areas
Foreign
defined
benefit plans
8.0-13.3
10.0-13.3
3.5-5.0
4.1-8.0
1.5-10.0
1.5-4.8
0.8-18.0
1.5-16.5
0.8-16.0
13-25
0.6-15.5
1.5-13.5
0.6-14.8
13-24
(years)
(years)
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
189
The effects of a possible change in the main actuarial assumptions at the end of the year are listed below:
(€ million)
December 31, 2018
Italian defined benefit plans
Foreign defined benefit plans
FISDE, foreign medical plans and other
Other benefit plans
December 31, 2017
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)
(58)
(7)
(5)
(13)
(72)
(7)
(3)
13
65
8
3
14
79
7
1
8
23
1
9
24
1
15
20
18
13
6
7
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 €129 million, of which
€48 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, 2018
2019
2020
2021
2022
2023
2024 and thereafter
Weighted average duration
(years)
December 31, 2017
2018
2019
2020
2021
2022
2023 and thereafter
Weighted average duration
(years)
Italian defined
benefit plans
Foreign defined
benefit plans
FISDE, foreign
medical plans and other
Other benefit plans
15
16
18
14
11
201
10.1
16
17
18
17
14
202
10.1
54
56
63
64
74
74
17.4
47
65
70
79
84
64
17.5
9
7
6
6
6
114
12.8
7
7
6
6
6
103
12.8
81
72
67
20
17
57
2.6
64
58
45
7
5
25
2.8
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018
190
22 | Deferred tax assets and liabilities
(€ million)
Deferred tax liabilities, gross
Deferred tax assets available for offset
Deferred tax liabilities
Deferred tax assets, gross (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
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
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:
December 31, 2018
7,956
(3,684)
4,272
7,615
(3,684)
3,931
December 31, 2017
10,169
(4,269)
5,900
8,347
(4,269)
4,078
Carrying amount at
December 31, 2018
Carrying amount at
December 31, 2017
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)
8,323
1,106
305
70
365
10,169
(5,240)
(2,747)
(2,164)
(1,404)
(801)
(395)
(194)
(130)
(534)
(13,609)
5,262
(8,347)
(€ million)
2018
Carrying amount - beginning of the year
Changes in accounting principles (IFRS 15)
Carrying amount restated - beginning of the year
Additions
Deductions
Currency translation differences
Decrease through loss of control of subsidiary
Other changes
Carrying amount at the end of the year
2017
Carrying amount at the beginning of the year
Additions
Deductions
Currency translation differences
Other changes
Carrying amount at the end of the year
Deferred
tax liabilities
Deferred
tax assets, gross
Accumulated
write-downs
of deferred tax assets
Deferred tax assets,
net of impairments
10,169
37
10,206
1,147
(802)
283
(2,778)
(100)
7,956
10,953
1,171
(835)
(1,123)
3
10,169
(13,609)
(237)
(13,846)
(1,478)
1,523
(278)
813
(90)
(13,356)
(13,698)
(2,341)
1,588
862
(20)
(13,609)
5,262
5,262
253
(43)
71
198
5,741
5,622
212
(349)
(202)
(21)
5,262
(8,347)
(237)
(8,584)
(1,225)
1,480
(207)
813
108
(7,615)
(8,076)
(2,129)
1,239
660
(41)
(8,347)
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
191
Carry-forward tax losses amounted to €19,108 million out of
which €13,753 million can be used indefinitely. Carry-forward tax
losses regarded Italian companies for €10,786 million and foreign
companies for €8,322 million. Deferred tax assets recognized
on these losses amounted to €2,615 million and €2,913 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.
An average 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 rate for foreign subsidiaries was 35%.
Accumulated write-down provisions of deferred tax assets related
to Italian companies for €4,133 million and foreign companies for
€1,608 million.
23 | Derivative financial instruments
(€ 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
Option embedded in convertible bonds
Gross amount
Offsetting
Net amount
Of which:
- current
- non-current
December 31, 2018
December 31, 2017
Fair value
asset
Fair value
liability
Level of Fair
value
Fair value
asset
Fair value
liability
Level of Fair
value
99
14
3
116
18
18
1,060
306
1
1,367
1,501
992
367
80
1,439
311
26
337
21
3,298
(1,636)
1,662
1,594
68
46
71
5
122
6
6
1,107
284
5
1,396
1,524
1,031
263
71
1,365
196
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
170
41
3
214
9
9
796
81
1
878
1,101
683
395
133
1,211
227
35
262
16
2,590
(1,279)
1,311
1,231
80
86
45
5
136
5
5
771
97
2
870
1,011
829
390
114
1,333
21
21
16
2,381
(1,279)
1,102
1,011
91
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
entered 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 mechanism 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 – Operating expenses. Information on hedged
risks and hedging policies is disclosed in note 27 – Guarantees,
commitments and risks - Risk factors.
Options embedded in convertible bonds of €21 million related to
equity-linked cash settled. More information is disclosed in note 18 –
Financial liabilities.
The offsetting of financial derivatives related to the Gas & Power
segment.
During the 2018, there were no transfers between the different
hierarchy levels of fair value.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018
192
Hedging derivative instruments are disclosed below:
(€ million)
Cash flow hedge derivatives
Derivatives on commodity
- Over the counter
- Future
Nominal amount of the
hedging instrument
December 31, 2018
Change in fair value
(effective hedge)
Change in fair value
(ineffective hedge)
3,528
71
3,599
404
(6)
398
2
(2)
In 2018, the exposure to the exchange rate risk deriving from
securities denominated in US dollars included in the strategic
liquidity portfolio amounting to €1,154 million was hedged by
using, in a fair value hedge relationship, negative exchange
differences for €35 million resulting on a portion of bonds
denominated in US dollars amounting to €1,140 million.
The breakdown of the underlying asset or liability by type of risk
hedged under cash flow hedge is provided below:
(€ million)
Cash flow hedge
Commodity price risk
- Forecast sales
December 31, 2018
Change of the
underlying asset used
for the calculation
of hedging
ineffectiveness
CFH reserve
Reclassification
adjustments
(389)
(389)
(13)
(13)
642
642
Eni’s results of operations are affected by fluctuations in the price
of commodities. In order to manage commodity price risk, Eni uses
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, electricity or emission certificates
that are not settled through physical delivery of the underlying asset
but are designated as hedging instruments in a cash flow hedge
relation.
The existence of a relationship between hedged item and hedging
instrument aimed to compensate its changes in value and the
relating hedging capability not affected by the level of credit risk of
the counterparty are verified for qualifying the operation as hedge.
The definition of the relationship between the quantity of the hedged
item and the quantity of the hedging instrument (the so-called hedge
ratio) is defined consistently with the entity’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 it was qualified as for hedge accounting.
More information is reported in note 27 – Guarantees, Commitments
and Risks - Risk factors.
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
2018
129
129
2017
12
(44)
(32)
2016
(1)
17
16
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: (i) the fair value
measurement and settlement of commodity derivatives which do
not meet the formal criteria to be treated in accordance with hedge
accounting under IFRS as they related to net exposure to commodity
risk and derivatives for trading purposes and proprietary trading
amounting to a net income of €129 million (net loss of €44 million in
2017 and net income of €36 million in 2016); and (ii) the fair value
valuation at certain derivatives embedded in the pricing formulas
of long-term gas supply contracts of the Exploration & Production
segment amounting to a net loss of €19 million in 2016.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
193
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
Options
2018
(329)
22
(307)
2017
809
28
837
2016
(494)
(12)
24
(482)
Net income from derivatives was recognized in connection with fair value
valuation of certain derivatives which do not meet the formal criteria to
be treated in accordance with hedge accounting under IFRS as they are
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, 2018, assets held for sale and the related directly
associated liabilities of €295 million and €59 million, respectively,
related to: (i) Agip Oil Ecuador BV, holder of the service contract
for the Villano oil field, for which a binding transfer agreement was
signed. The carrying amounts of assets held for sale and directly
associated liabilities amounted to €274 million (of which current
assets for €81 million) and €59 million respectively (of which
current liabilities for €33 million); (ii) the sale of tangible assets and
minority interests for a total carrying amount of €21 million.
In the course of 2018, Eni finalized the sale of: (i) the 98.99% (entire
stake owned) of Tigáz Zrt and Tigáz DSO (100% Tigáz Zrt) to the
group MET Holding AG, including Eni’s gas distribution operations in
Hungary; (ii) the business relating to a 26.25% stake of Lasmo Sanga
Sanga Ltd (entire stake owned) of the PSA in the Sanga Sanga gas
and condensates field; (iii) the sale of a 50% (entire stake owned)
interest in the joint venture Unimar Llc.
25 | Shareholders’ equity
As of January 1, 2018, the effects of the application of IFRS 9 and IFRS 15 are the following:
(€ million)
Carrying amount at December 31, 2017
Changes in accounting principles (IFRS 9)
Changes in accounting principles (IFRS 15)
Carrying amount at January 1, 2018
Share
capital
4,005
4,005
Retained
Earnings
35,966
294
(49)
36,211
Other
reserves
4,685
Net profit
(loss)
3,374
4,685
3,374
Total
48,030
294
(49)
48,275
More information about the application of IFRS 9 and IFRS 15 is disclosed in note 3 – Changes in accounting policies.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018
194
(€ 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, 2018
4,005
36,702
6,605
959
581
(9)
(130)
66
15
190
(581)
(1,513)
4.126
51.016
December 31, 2017
4,005
35,966
4,818
959
581
183
(114)
90
190
(581)
(1,441)
3.374
48.030
More information about the application of IFRS 9 and IFRS 15 is
disclosed in note 3 – Changes in accounting policies.
2018, to shareholders on the register on 21 May 2018, record date on
22 May 2018. Total dividend per share in 2017 was €0.80.
Share capital
As of December 31, 2018, 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, 2017).
On May 10, 2018, Eni’s Shareholders’ Meeting resolved the
distribution of a dividend of €0.40 per share, with the exclusion of
treasury shares held at the ex-dividend date, in full settlement of the
2017 dividend of €0.40 per share, of which €0.40 per share paid as
interim dividend in September 2017. The balance was paid on 23 May
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
(€ million)
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
Reserve as of December 31, 2016
Changes of the year
Foreign currency translation differences
Reclassification adjustments
Reserve as of December 31, 2017
Cash flow
hedge derivatives
Defined
benefit plans
e
v
r
e
s
e
r
s
s
o
r
G
240
399
d
e
r
r
e
f
e
D
x
a
t
s
e
i
t
i
l
i
b
a
i
l
(57)
(116)
e
v
r
e
s
e
r
t
e
N
183
283
(10)
(642)
(13)
246
(59)
53
240
3
174
4
(7)
(468)
(9)
(57)
14
(14)
(57)
189
(45)
39
183
e
v
r
e
s
e
r
s
s
o
r
G
(133)
(15)
1
4
d
e
r
r
e
f
e
D
x
a
t
s
e
i
t
i
l
i
b
a
i
l
19
(2)
(1)
(3)
e
v
r
e
s
e
r
t
e
N
(114)
(17)
1
(143)
13
(130)
(99)
(33)
(1)
(13)
29
3
(112)
(4)
2
(133)
19
(114)
Other comprehensive
income on
equity-accounted
investments
90
(24)
66
21
69
90
Investments
valued
at fair value
15
15
Reserve related to investments valued at fair value does not include the effects of first application of IFRS 9 of €681 million recognized in
retained earnings.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
195
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.
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.
Interim dividend
The interim dividend for the year 2018 amounted to €1,513 million
corresponding to €0.42 per share, as resolved by the Board of
Directors on September 13, 2018, in accordance with Article 2433-
bis, paragraph 5 of the Italian Civil Code; the dividend was paid on
September 26, 2018.
Treasury shares
A total of 33,045,197 Eni’s ordinary shares (same amount as of
December 31, 2017) were held in treasury for a total cost of €581
million (same amount as of December 31, 2017). On April 13,
Distributable reserves
As of December 31, 2018, Eni shareholders’ equity included
distributable reserves of approximately €46 billion.
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 account policies
- elimination of unrealized intercompany profits
- deferred taxation
Non-controlling interest
As recorded in Consolidated Financial Statements
Net profit
Shareholders’ equity
2018
3,173
2017 December 31, 2018
42,615
3,586
December 31, 2017
42,529
(134)
(466)
7,183
6,110
862
177
59
4,137
(11)
4,126
(1)
202
(88)
144
3,377
(3)
3,374
153
2,000
(519)
(359)
51,073
(57)
51,016
145
719
(807)
(617)
48,079
(49)
48,030
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018
196
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
Gain on a bargain purchase
Purchase price
less:
Cash and cash equivalents
Investment in 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 OCI
Fair value of share capital held after the sale of control
Fair value valuation for business combination
Gain (loss) on disposal
Non-controlling interest
Selling price
less:
Cash and cash equivalents
Disposal of consolidated subsidiaries and businesses net of cash and cash equivalent divested
2018
2017
2016
44
198
11
(47)
206
(50)
(8)
148
(29)
119
328
5,079
785
(3,470)
2,722
113
(3,498)
889
13
166
814
(252)
(205)
523
2,148
239
2,671
6,526
8,615
(5,415)
(6,334)
3,392
7
(1,006)
11
(1,872)
532
(286)
(47)
(9)
2,662
(894)
(362)
Investments in 2018 concerned: (i) the acquisition of the business by
Versalis Spa of the “bio” activities of 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
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 interest 69.60%), that will develop the project portfolio of
the combined entities. The operation entailed the exclusion from the
consolidation area 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 & Tobago for €10 million.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
27 | Guarantees, commitments and risks
Guarantees
Commitments and risks
(€ million)
Consolidated subsidiaries
Unconsolidated subsidiaries
Joint ventures and associates
Others
197
December 31, 2018
5,082
196
4,056
163
9,497
December 31, 2017
5,595
181
10,046
352
16,174
The parent company of the Eni Group issued guarantees to cover the
contractual obligations held by third parties towards Eni’s affiliates 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 value of the contract is €4,586 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 interest 25%). This entity will operate the vessel in accordance
to a service agreement 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 through a subsidiary 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 contract (EPCIC), up to the maximum liability of €1,147
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 €4,082 million. During the construction and the commissioning
of the FLNG plant, the project financing agreement will be supported by
a debt service undertaking, up to a maximum liability of €1,397 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 change into a
non-recourse one, terminating the obligations of the venturers of Area
4. Once vessel operations start, the lenders will be guaranteed only by
the vessel cash flows, 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 €121 million in Eni’s share; (ii)
the share of the debt service undertaking by ENH up to a maximum liability
of €155 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
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 €1,309 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.
Other guarantees issued on behalf of consolidated subsidiaries primarily
consisted of: (i) guarantees given to third parties relating to bid bonds
and performance bonds for €2,576 million (€2,312 million at December
31, 2017); (ii) a bank guarantee of €1,010 million (same amount as of
December 31, 2017) issued on behalf of GasTerra in order to obtain the
renunciation to a temporary seizure order on Eni’s investment in Eni
International BV, requested and obtained by a Netherlands Court in July
2016. At December 31, 2018, the underlying commitment covered by such
guarantees was €5,000 million (€5,564 million at December 31, 2017).
Unsecured guarantees and other guarantees issued on behalf of joint
ventures and associates primarily consisted of: (i) an unsecured
guarantee of €499 million (€6,122 million at December 31, 2017) given
by Eni SpA to Treno Alta Velocità - TAV SpA (now RFI - Rete Ferroviaria
Italiana SpA) for the proper and timely completion of a project relating
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 198
to the Milan-Bologna fast track railway by CEPAV (Consorzio Eni per
l’Alta Velocità) Uno (associated company of Saipem); the decrease of
€5,623 million is due to the cancellation of the guarantees related to the
completion of the main lots of the project; (ii) unsecured guarantees
and other guarantees given to banks in relation to loans and lines of
credit received for €1,664 million (€1,623 million at December 31,
2017), of which €1,397 million (€1,334 million at December 31, 2017)
related to guarantees issued as part of the development project of the
gas reserves at the Coral discovery 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 (iii) guarantees given to third parties relating to bid bonds and
performance bonds for €1,644 million (€2,122 at December 31, 2017),
of which €1,147 million (€1,094 million at December 31, 2017) related
to guarantees issued for the construction of the FLNG as part of the
development project of the gas reserves at the Coral project offshore
Mozambique and €279 million given on behalf of Saipem Group (€1,008
million at December 31, 2017); (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%) as security against payment
commitments of fees in connection with the regasification activity for
€177 million (€169 million at December 31, 2017). At December 31,
2018, the underlying commitment covered by such guarantees was
€2,159 million (€2,594 million at December 31, 2017).
Commitments and risks
(€ million)
Commitments
Risks
December 31, 2018
54,611
673
55,284
December 31, 2017
14,498
691
15,189
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 €52,397 million
(€11,289 million at December 31, 2017).
The increase of €41,108 million essentially related to: (a) the issue of
parent company guarantees, in relation to transactions with the Abu Dhabi
State oil company, ADNOC, whereby Eni acquired participating interests in
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
for a maximum amount of €13,094 million and in the concession under
development of Gasha (Eni’s interest 25%) for a period of 40 years and
a maximum amount of €21,824 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) the issue of
parent company guarantees for €6,831 million 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;
(ii) commitments assumed by Eni USA Gas Marketing Llc towards
Angola LNG Supply Service Llc for the purchase of volumes of re-gasified
gas at the Pascagoula plant (United States) over a twenty-year period
(until 2031). The expected commitments were estimated at €2,079
million (€2,113 million at December 31, 2017) and included in off-
balance sheet contractual commitments in the table “Future payments
under contractual obligations” in the paragraph Liquidity risk. 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 supply of long-term regasification and import
services (until 2031) amounting at the opening balance to €948 million
(undiscounted) ceased due to an arbitration award, ruling that the
commitment was resolved by March 1, 2016 and recognizing to the
counterparties an equitable compensation of €324 million, accounted
as expense in the income statement. 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; (iii) a
memorandum of intent signed with the Basilicata Region, whereby Eni
has agreed to invest €116 million (€128 million at December 31, 2017)
in the future, also on account of Shell Italia E&P SpA, in connection with
Eni’s development plan of oilfields in Val d’Agri. The commitment has
been included in the off-balance sheet contractual commitments in the
following paragraph “Liquidity risk”.
Risks concerned potential risks associated with contractual
assurances given to acquirers of certain investments and businesses
of Eni for €244 million (€235 million at December 31, 2017) and the
value of assets of third parties under the custody of Eni for €429
million (€456 million at December 31, 2017).
Non-quantifiable commitments
A parent company guarantee was issued on behalf of Cardón IV SA
(Eni’s interest 50%), a joint venture that is currently operating the
Perla gas field located in Venezuela, for the supplying 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 share (50%) of the contractual volumes
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 199
of gas to be delivered to PDVSA GAS amounted to a total of €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.
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.
Risk factors
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 of 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
relation 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 operations 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’s finance department and Eni Finance International
SA manage subsidiaries’ financing requirements in and outside Italy,
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 operations 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 the 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 of 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 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 on the marketplace.
According to the targets of financial structure included in the financial
plan approved by the Board of Directors, Eni has 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 the capital, manages such reserve and its
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 200
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 the euro (mainly the US dollar).
Revenues and expenses denominated in foreign currencies may be
significantly affected by exchange rates 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 the euro are translated from their functional
currency into euro. Generally, an appreciation of the US dollar versus
the 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 the 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 central finance department, which pools 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 the
management’s finance plans. The Group’s central finance department
pools 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.
Changes in fair value of those derivatives are normally recognized
through the profit and loss account, as they do not meet the formal
criteria to be accounted for under the hedge accounting method. 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 as 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 finalized to the
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). In the proprietary trading exposures are included the origination
activities, 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. 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
and the exposure to commodity prices through the trading unit of
Eni Trading & Shipping 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,
electricity or emission certificates. Such derivatives are evaluated at
fair value based on market prices provided from specialized sources or,
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 201
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 evaluated 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 Group 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 financial
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 (USD portfolio).
In 2018, the investment portfolio Euro has maintained an average
credit rating of A-/BBB+, the investment portfolio USD has maintained
an average credit rating of A+/A, both in line with the year 2017.
The following table shows amounts in terms of VaR, recorded in 2018
(compared with 2017) 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
3.65
0.57
2018
Low
1.80
0.09
Average
2.73
0.28
At year end
2.99
0.25
High
3.76
0.57
2017
Low Average
2.38
1.72
0.22
0.08
At year end
2.58
0.26
(a) Value at risk deriving from interest and exchange rates exposures include the following finance department: Eni Corporate Treasury Department, Eni Finance International SA, Banque Eni SA and Eni
Finance USA Inc.
(Value at risk - Historic simulation weighted method; holding period: 1 day; confidence level: 95%)
(€ million)
Commercial exposures - Management Portfolio(a)
Trading(b)
High
18.60
2.28
2018
Low
6.79
0.26
Average
11.04
0.73
At year end
7.50
0.27
High
21.14
2.29
2017
Low Average
12.24
5.15
0.79
0.21
At year end
5.15
0.66
(a) Refers to the Gas & 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 and 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, in 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)
(a) Management of strategic liquidity portfolio starting from July 2013.
(Sensitivity - Dollar value of 1 basis point - DVBP)
2018
High
0.35
Low
0.25
Average
0.29
At year end
0.25
High
0.41
2017
Low Average
0.35
0.27
At year end
0.27
($ million)
Strategic liquidity(a)
2018
High
0.04
Low
0.01
Average
0.02
At year end
0.02
High
0.04
2017
Low Average
0.03
0.02
At year end
0.03
(a) Management of strategic liquidity portfolio in $ currency starting from August 2017.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018
202
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 and with regard to the latter, among of the others, of the
centralized finance model adopted.
The Company adopted a model to quantify and control the credit risk
based on the evaluation of the expected loss for which the probability
of default and the capacity to recover credits in default is estimated
through the so-called Loss Given Default.
In the credit risk management and control model, credit exposures are
distinguished by commercial nature, substantially in relation to the
structured contracts on commodities related to Eni’s core business,
and by financial nature, substantially in relation to the financial
instruments 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 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, the risk is determined by distinguishing customers in
homogeneous risk clusters based on historical series of data relating
to payments made, 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 Group
operating finance department, including Eni’s subsidiary Eni Trading
& Shipping which specifically engages in commodity derivatives
transactions and by Group companies and Divisions, 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 on 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 €16.7 billion were drawn as of
December 31, 2018.
The Group has credit ratings of A- outlook stable and A-2, respectively
for long and short-term debt, assigned by Standard & Poor’s and
Baa1 outlook stable and P-2, respectively for long and short-term
debt, assigned by Moody’s. 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 Standard & Poor’s and Moody’s, 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 2018, Moody’s reduced the
rating of Eni by one notch (from A3 to Baa1) following the reduction in
the rating assigned to Italy (from Baa2 to Baa3, outlook stable).
In the course of the 2018, Eni issued bonds amounting to €2.8 billion,
of which €1.1 billion were issued under the Euro Medium Term Notes
program and €1.7 billion through a dual-tranche issue on the US
market and on international markets.
As of December 31, 2018, Eni maintained short-term unused borrowing
facilities of €12,484 million. Long-term committed unused borrowing
facilities amounted to €5,214 million due beyond 12 months. These
facilities bore interest rates and fees for unused facilities that reflected
prevailing market conditions.
Finance debt repayments including expected payments for
interest charges and derivatives
The table below summarizes the Group main contractual obligations for
finance liability repayments, including expected payments for interest
charges and derivatives.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 203
(€ million)
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
December 31, 2017
Non-current financial liabilities (including the current portion)
Current financial liabilities
Fair value of derivative instruments
Interest on finance debt
Financial guarantees
2019
2020
2021
Maturity year
2022
2023
2024 and thereafter
Total
3,301
2,182
1,445
6,928
655
668
2,958
1,541
1,253
2,714
13
2,971
545
1
1,542
436
21
1,274
330
2,714
320
11,723
5
11,728
1,677
23,490
2,182
1,485
27,157
3,963
668
2018
2019
2020
Maturity year
2021
2022
2023 and thereafter
Total
2,000
2,242
1,011
5,253
582
473
4,084
2,857
1,279
1,246
10,810
64
4,148
511
10
2,867
411
1
1,280
304
16
1,262
250
10,810
1,455
22,276
2,242
1,102
25,620
3,513
473
Trade and other payables
The table below summarizes the Group trade and other payables by maturity.
(€ million)
December 31, 2018
Trade payables
Other payables and advances
December 31, 2017
Trade payables
Other payables and advances
Maturity year
2019
2020-2023
2024 and thereafter
Total
11,645
5,102
16,747
59
59
Maturity year
11,645
5,257
16,902
96
96
2018
2019-2022
2023 and thereafter
Total
10,890
5,858
16,748
19
19
10,890
5,903
16,793
26
26
Expected payments by period under contractual obligations
In addition to trade and financial 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 the non-performance.
The Company’s main contractual obligations at the balance sheet date
comprise: (i) 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; (ii)
operating leases for tangible assets, of which primarily for FPSO units of
the E&P segment, in particular FPSOs operating in the offshore projects
at Cape Three Points in Ghana and at the 15/06 block in Angola, with a
duration of between 11 and 14 years.
The table below summarizes the Group principal contractual obligations
as of the balance sheet date, shown on an undiscounted basis.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 204
(€ million)
Operating lease obligations(a)
Decommissioning liabilities(b)
Environmental liabilities
Purchase obligations(c)
- Gas
take-or-pay contracts
ship-or-pay contracts
- Other purchase obligations
Other obligations
- Memorandum of intent - Val d’Agri
2019
776
335
349
14,674
11,886
1,164
1,624
8
8
16,142
2020
601
294
321
11,258
10,470
558
230
1
1
12,475
2021
481
407
254
10,649
9,995
482
172
1
1
11,792
Maturity year
2022
303
260
239
9,683
2023
268
124
188
9,546
9,276
382
25
1
1
10,486
9,210
324
12
1
1
10,127
2024 and thereafter
1,524
12,394
1,245
76,014
Total
3,953
13,814
2,596
131,824
75,035
941
38
125,872
3,851
2,101
104
104
91,281
116
116
152,303
(a) There are no significant restrictions provided by these operating leases which limit the ability of the Company to pay dividend, use assets or to take on new borrowings.
(b) 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.
(c) 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 €32.7 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
2019
6,492
2020
4,917
Maturity year
2022
1,910
2021
3,458
2023 and thereafter
3,629
Total
20,406
Other information about financial instruments
The carrying amount of financial instruments and the relevant economic and equity effect consisted of the following:
2018
2017
Finance income (expense) recognized in
Finance income (expense) recognized in
Carrying
amount
Profit
and loss account
Other
comprehensive
income
Carrying
amount
Profit
and loss account
Other
comprehensive
income
73
231
919
207
6,012
209
32
(178)
6,552
177
(111)
793
(€ million)
Held-for-trading financial instruments
Financial assets held for trading(a)
Non-hedging and trading derivatives(b)
Non-current financial instruments
Held-to-maturity securities(a)
Available-for-sale financial instruments
Securities(a)
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)
(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 €129 million (loss for €44 million in 2017) and as loss within “Finance
income (expense)” for €307 million (income for €837 million in 2017).
(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 €415 million (net
impairment losses for €913 million in 2017) and as income within “Finance income (expense)” for €69 million (expenses for €45 million in 2017), including interest income calculated on the basis
of the effective interest rate of € 38 million.
(e) In the profit and loss account, income or expense were recognized as expense within “Finance income (expense)” for €139 million (€116 million in 2017), including interest income calculated
on the basis of the effective interest rate of €129 million (€128 million in 2017) and net impairment losses for €275 million.
(f) In the profit and loss account, income or expense were recognized as expense within “Finance income (expense)” for €615 million (€1,137 million in 2017), including interest income calculated
on the basis of the effective interest rate of €605 million (€654 million in 2017).
(g) In the profit and loss account, income or expense were recognized within “Net sales from operations” and “Purchase, services and other” as income for €642 million (expense for €54 million in
2017), and as income within “Other operating income (expense)” for €12 million in 2017.
14,145
1,489
64
16,902
25,865
(51)
(1,137)
(42)
(28)
(615)
642
15,583
1,918
16,793
24,707
(958)
(116)
(343)
(139)
(243)
(4)
(6)
15
9
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 205
Disclosures about the offsetting of financial instruments
The table below summarizes the disclosures about the offsetting of financial instruments.
(€ million)
December 31, 2018
Financial assets
Trade and other receivables
Other current assets
Financial liabilities
Trade and other liabilities
Other current liabilities
December 31, 2017
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
15,634
3,894
18,280
5,616
16,636
2,852
17,963
2,794
1,533
1,636
1,533
1,636
1,215
1,279
1,215
1,279
14,101
2,258
16,747
3,980
15,421
1,573
16,748
1,515
The offsetting of financial assets and liabilities related to the offsetting
of: (i) assets and liabilities for current financial derivatives for €1,636
million (€1,279 million at December 31, 2017); and (ii) receivables and
payables pertaining to the Exploration & Production segment towards
state entities for €1,347 million (€1,041 million at December 31, 2017);
(iii) trade receivables and trade payables pertaining to Eni Trading &
Shipping Inc for €186 million (€174 million at December 31, 2017).
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 for contingencies
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.
A description of the most significant proceedings currently pending
is provided in the following paragraph. 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.
(ii)
1. Environment, health and safety
1.1. Criminal proceedings in the matters of environment,
health and safety
(i)
Syndial SpA (company incorporating EniChem Agricoltura SpA
– Agricoltura SpA in liquidation – EniChem Augusta Industriale
Srl – Fosfotec Srl) – 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’s subsidiary in 1991 following the divestment of
an industrial complex by Montedison (now Edison SpA). The landfill
site had been filled with industrial waste from Montedison activities
until 1989 and then no additional waste was discharged there. Eni’s
subsidiary carried out the clean-up of the landfill in 1999 through
2000. The defendants are certain managers at Eni’s subsidiaries
that have owned and managed the landfill since 1991. Independent
consultants performed an assessment during the 2014. Once the
consultants completed their work, the acts returned to the Public
Prosecutor of Crotone for the next step and possible indictment.
The proceeding continues with the examination of the dismissal
request submitted by the defense. The Municipality of Crotone will
act as plaintiff. The Prosecutor of Crotone notified the conclusion of
the preliminary investigations. In March 2019, the Public Prosecutor
requested the acquittal of all defendants. In April 2017, the Public
Prosecutor of Crotone had started another criminal proceeding
concerning the clean-up of the area called “Farina Trappeto”. The
Company presented a new clean-up project already deemed
approvable by the Ministry of the Environment. Final authorizations
for this project are pending. The Company requested to dismiss also
this second proceeding.
Syndial SpA and Versalis SpA – Porto Torres – Prosecuting body:
Public Prosecutor of Sassari. In July 2011, the Public Prosecutor
of Sassari (Sardinia) resolved that a number of officers and senior
managers of companies engaging in petrochemical operations at
the site of Porto Torres, including the manager responsible for plant
operations of the Company’s subsidiary Syndial, would stand trial
due to allegations of environmental damage and poisoning of water
and crops. The Province of Sassari, the Municipality of Porto Torres
and other entities have been acting as plaintiffs. The Judge for the
Preliminary Hearing admitted as plaintiffs the above-mentioned
parts, but based on the exceptions issued by Syndial on the lack
of connection between the action and the charge, denied that
the claimants would act as plaintiff with regard to the serious
pathologies related to the existence of poisoning agents in the
marine fauna of the industrial port of Porto Torres. In February 2013,
the Prosecutor of Sassari notified the conclusion of preliminary
investigations and requested a new imputation for negligent
behaviour instead of illicit conduct. In the conclusions of the
preliminary hearing, the Court of Sassari dismissed the accusation
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 206
because of the statute of limitations. The Public Prosecutor filed an
appeal before the Third Instance Court. After a hearing on a question
of constitutional legitimacy concerning the period for the statute
of limitations for the crime of disaster, the Third Instance Court
recognized its validity and therefore accepted the claim and sent
all the acts to the Constitutional Court. The Constitutional Court
declared the question unfounded, considering that the statute
of limitations for fraudulent hypothesis and the corresponding
culpable hypothesis is an expression of a non-unreasonable
legislative discretion, assuming that, in relation to certain culpable
offenses causing social alarm, the complexity of the necessary
investigations justifies a lengthening of the limitation periods.
The Third Instance Court returned the documents to the Public
Prosecutor of Sassari who proceeded to resubmit the request for
indictment. The preliminary hearing is underway.
(iii) Syndial SpA and Versalis SpA – Porto Torres dock. In July 2012,
the Judge for the Preliminary Hearing, following a request of the
Public Prosecutor of Sassari, requested the performance of a
probationary evidence relating to the functioning of the hydraulic
barrier of Porto Torres site (ran by Syndial SpA) and its capacity
to avoid the dispersion of contamination released by the site in
the near portion of sea. Syndial SpA and Versalis SpA have been
notified that its chief executive officers and other managers are
being investigated. The Public Prosecutor of the Municipality of
Sassari requested that the above-mentioned individuals would
stand trial. The plaintiffs, the Ministry of Environment and the
Sardinia Region claimed environmental damage in an amount
of €1.5 billion. On the hearing dated July 2016, the Judge
pronounced an acquittal sentence for all defendants of Syndial
and Versalis with respect to the crimes of environmental disaster.
Three Syndial managers were found guilty of environmental
disaster which took place in the area in the period limited to
August 2010-January 2011 and condemned to one-year prison,
with a suspended sentence. The Judge did not mention any
possible malfunctioning of the hydraulic barrier of Porto Torres
site or ineffective implementation of any emergency safety
measure, as claimed by the Public Prosecutor. Syndial filed an
appeal against this decision.
(iv) Syndial SpA – The illegal landfill in Minciaredda area, Porto
Torres site. In July 2015, the Judge for the Preliminary Hearing of
the Court of Sassari, on request of the Public Prosecutor, seized of
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 provision
involved as well Syndial in accordance with the Legislative
Degree No. 231/01. With reference to the clean-up activities in the
Minciaredda area, on January 27, 2016 the relevant administrative
body approved the project for the soil clean-up in the Minciaredda
area. Syndial obtained all the necessary ministerial and judicial
authorizations to start the remediation project. Following the
preliminary investigations, the Public Prosecutor requested a
referral to trial. Some environmental associations joined the
proceeding as plaintiffs. The proceeding is still pending.
Syndial SpA – The Phosphate deposit at Porto Torres site (1).
In 2015, the Judge for the Preliminary Hearing of the Court of
Sassari, accepting a request of the Public Prosecutor of Sassari,
seized – as a preventive measure – the area of “Palte Fosfatiche”
(v)
(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. Subsequent to a specific request, both the
Public security officer of Sassari and the Judge for the Preliminary
Hearing of the Court of Sassari authorized to implement better
delimitations of the landfill area, to provide the area with devices
for monitoring the level of environmental pollutants and meteoric
waters. The investigations are underway.
(vi) 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). These
waters are being collected by Syndial following authorizations
of the Public security officer of Sassari and the Judge for the
Preliminary Hearing of the Court of Sassari. The indicted have
also been served a notice of investigation for alleged crimes of
omitted clean-up and management of radioactive waste. The
Public Prosecutor decided to suspend the activities of collection,
containment and preservation of the area, in spite that those
activities have already been authorized. The request filed for the
removal of the phosphates deposit was authorized by the Public
Prosecutor in October 2018. The investigations are underway.
(vii) Syndial SpA – Proceeding on the asbestos at the Ravenna
site. A criminal proceeding is pending before the Tribunal of
Ravenna about the crimes of culpable manslaughter, injuries
and environmental disaster, which would have been allegedly
committed by former Syndial employees at the site of Ravenna.
The site was taken over by Syndial 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. The
advocacy of Syndial claimed the statute of limitation about the
instance of environmental disaster for certain instances of diseases
and deaths. The Judge for the Preliminary Hearing at Ravenna
decided that all defendants would stand trial and ascertained
the statute of limitation only with reference to certain instances
of crime of culpable injury. Syndial signed some settlements.
In November 2016, the Judge acquitted the defendants for all
the contested cases except for one for which ruled a decision
of conviction. The defendants, the Prosecutor and the plaintiffs
appealed the decision. The proceeding was suspended following the
filing of an appeal before the Third Instance Court.
(viii) Raffineria di Gela SpA – 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 environmental
disaster, unauthorized waste disposal and unauthorized spill
of industrial wastewater. The Gela Refinery has been sued for
administrative offence in accordance with the 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
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 207
merged into this proceeding the other investigations related to the
pollution occurred at the other sites of the Gela refinery as well
as hydrocarbon spills at facilities of EniMed. The proceeding is
pending at the preliminary hearings.
(ix) Eni SpA – Proceeding Val d’Agri. On March 2016, the Italian Public
Prosecutor’s Office of Potenza started a criminal investigation in
order to ascertain the existence of an 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 decided for the domiciliary detention of 5 Eni
employees and to put under seizure certain plants functional
to the production activity of the Val d’Agri complex which,
consequently, was shut down (60 KBOE/d net to Eni). From
the commencement of the investigation, Eni has carried out
several technical and environmental surveys, with support of
independent experts of international reach, who recognized
a full compliance of the plant and the industrial process with
requirements of the applicable laws, as well as with best available
technologies and international best practices. The Company
studied certain corrective measures to upgrade plants which,
although being not a structural solution, 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 measures comprised building a
gathering system of inherent liquid associated with the extraction
of hydrocarbons at the gas lines. Those corrective measures
were favourably reviewed by the Public Prosecutor. The Company
restarted the plant through reinjections into the Costa Molina
2 well on August 2016. Simultaneously, a local administrative
agency (the Region) requested a new administrative procedure
to grant Eni a comprehensive environmental authorization to
operate the facilities. In relation to the criminal proceeding, the
Public Prosecutor’s Office requested the indictment for all the
defendants and the Company. At the preliminary hearing held in
April 2017, prosecutor reiterated its request of indictment. The trial
started in November 2017 and is in the hearings stage.
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, following the request of the Consultant of the
Prosecutor, the National Mining Office for Hydrocarbons and Geo-
resources (UNMIG) requested the transfer to a different task of
25 employees of the COVA center for improper assessment of their
suitability to the current tasks expressed by the Eni personnel in
charge of assessing the health risk profile of employees. Against
this decision, the Company filed a formal objection and the UNMIG
repealed the resolution issued. Furthermore, in October 2017, the
Prosecutor’s Office changed the crime allegations to disaster,
murder and negligent personal injury, also alleging breaches of
health and safety regulations. Given the level of risk, in December
(x)
2017, Eni filed a request for pre-trial hearing for gathering
evidence on the matter that was rejected by the Judge.
(xi) Eni SpA – Proceeding Val d’Agri – Tank spill. On February 2017,
the Italian police department of Potenza ascertained a stream of
water contaminated by hydrocarbon traces of unknown origin,
flowing inside a little shaft located outside the Val d’Agri Oil Center
(COVA). The activities carried out by Eni at the COVA aimed at
reconstructing the origin of the contamination and have identified
the cause in a failure of a tank, while outside of the COVA, following
the environmental monitoring implemented, emerged 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 the Legislative
Decree 152/06 and started certain emergency safe-keeping
operations at the areas subject to 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 the
existence of illicit environmental pollution against 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 the Legislative
Decree 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 crime for environmental
disaster and of culpable conduct committed in February 2017.
Investigations are ongoing. In April 2017, Eni, on its own initiative,
suspended the industrial activity at the COVA, anticipating the
provisions of the Regional Council Resolution. In July 2017, Eni
restarted the plant’s operational activities. The resumption follows
the approval from the Basilicata Region confirming the functionality
of the plant and the presence of all necessary safety conditions.
During the temporary closure, Eni performed all the requirements
provided for by the relevant authorities, including the provision
of a double bottom to the tank where the spillage occurred. The
Company compensated the damage to certain landlords of areas
close to the COVA, which were affected by the spillover. Discussions
are ongoing with other claimants. 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 that the
loss was promptly and efficiently controlled and there were no
situations of serious danger to human health and the environment.
(xii) Raffineria di Gela SpA – Eni Mediterranea Idrocarburi SpA –
Waste management of the landfill Camastra. In June 2018,
Eni’s subsidiaries Raffineria di Gela SpA and Eni Mediterranea
Idrocarburi SpA were notified by the Public Prosecutor of Palermo
(Sicily) of a notice of conclusion of preliminary investigations
relating allegations of unlawful disposal of industrial waste
deriving from the reclaiming activities of soil, which were
discharged at a landfill owned by a third party. The Prosecutor
charged the alleged crime against the then chief executive
officers of the two subsidiaries, whereas the legal entities have
been charged with the liability pursuant by Legislative Decree No.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 208
231/01. The alleged wrongdoing related to the willful falsification
of the waste certification for purpose of discharging at the landfill.
(xiii) Syndial SpA – Environmental disaster at Ferrandina. In January
2018, the Public Prosecutor of Matera commenced a criminal
proceeding against a manager of the Eni subsidiary Syndial 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. Following an interrogation of the investigated manager, the
prosecutor resolved to request his indictment.
(xiv) Versalis SpA – Preventive seizure at the Priolo Gargallo plant.
In February 2019, the Court of Syracuse on request of the Public
Prosecutor ordered the precautionary seizure of the Priolo/
Gargallo plant as part of an ongoing investigation about air
emissions at the industrial complex. However, the Eni subsidiary
has been given permission to continue running the industrial
activity at the plant. A preliminary review, performed by technical
consultants appointed by the Public Prosecutor, found that the
spots of the plant designed to channel and release emissions
compliance failed to comply with best available techniques
(BAT). The Tribunal measure comprised certain interrelations
between BATs and the obtained Environmental Integrated
Authorizations, which according to the consultants would not
be legitimate because they have been found to be inconsistent
with applicable regulations. Few years ago Versalis implemented
certain plant upgradings designed to comply with measures
requested by the Public Prosecutor and his consultants. Based
on this, management filed an appeal against the measure of
precautionary seizure of the plant before a Review Court. On
March 26, 2019, the Review Court annulled the decree and
ordered the release of seizure of the plant.
(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. On the basis of the first investigations, part
of the structure on which a crane and the relative control cabin
was installed fell into the sea striking a supply vessel and causing
injuries to two contract workers and the death of an Eni employee
who was inside the control cabin of the crane. The Public Prosecutor
of Ancona opened an investigation against unknown persons and
ordered further technical appraisals relating the crane.
1.2. Civil and administrative proceedings in the matters of
environment, health and safety
(i) Syndial SpA – Summon for alleged environmental damage caused
by DDT pollution in the Lake Maggiore – Prosecuting body: Ministry
for the Environment. In May 2003, the Ministry for the Environment
summoned Syndial requesting the compensation of an alleged
environmental damage caused by the activity at the Pieve Vergonte
plant in the years 1990 through 1996. With a temporarily executive
sentence dated July 2008, the District Court of Turin sentenced
the subsidiary Syndial SpA to compensate environmental damages
amounting to €1,833.5 million, plus legal 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 charged with respect to the volume of pollutants
ascertained by the Italian Environmental Minister. In July 2009,
Syndial filed an appeal against the above-mentioned sentence, and
consequently the proceeding continued before a Second Degree
Court of Turin that requested a technical appraisal on the matter. The
consultants validated the technical appraisal and the other technical
assessments that were carried out by the Company together with
local and national technical entities. The consultants 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 which could be
recorded concerned the fishing activity, with an estimated damage
of €7 million which could be already restored through the measures
proposed by Syndial; (iii) the necessity and convenience of dredging
should be definitely excluded, both from the legal and scientific point
of view, while confirming technical and scientific correctness of the
Syndial’s approach based on the monitoring of the process of natural
recovery, which is estimated to require 20 years. In March 2017, the
Second Degree Court: (i) excluded the application of compensation
for monetary equivalent (Article 18 of Law 349/1986); (ii) annulled
the monetary compensation of €1.8 billion requesting Syndial to
perform the already approved cleanup 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 Syndial failure or misperformance, is estimated
at €9.5 million. The cleanup project filed by Syndial was ratified by
local and governmental 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 (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) Syndial SpA – Versalis SpA – Eni SpA (R&M) – Augusta harbor.
The Italian Ministry for the Environment with various administrative
acts required companies that were running 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 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 of Catania. In October
2012, the Court ruled in favor of Eni’s subsidiaries against the
Ministry prescriptions about 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 co-owner companies
in December 2017, constitutes a formal notice for environmental
damage. The Administrative Council of the Sicilian Region ruled on
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the appeals pending against various sentences of the Regional
Administrative Court and essentially confirmed the cancellation of
all administrative provisions subject to the dispute. The prescriptive
framework for the companies thus becomes clear and definitive.
The annulment of the provisions has, inter alia, retroactive effect at
the time of their adoption and therefore allows to exclude the risk of
claims against any possible breach of administrative provisions.
(iii) Eni SpA – Syndial SpA – Raffineria di Gela – Claim for preventive
technical inquiry. In February 2012, Eni’s subsidiaries Raffineria di
Gela SpA and Syndial 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
born malformed in the Municipality of Gela between 1992 and 2007.
The claim for preventive technical inquiry aimed at verifying the
relation of causality between the malformation pathologies suffered
by the children of the plaintiffs and the environmental pollution
caused by the Gela site (pollution deriving from activities conducted
at the industrial plant by Raffineria di Gela SpA and Syndial SpA),
quantifying the alleged damages suffered and eventually identifying
the terms and conditions to settle the claim. In any case, the same
issue was the subject of previous criminal proceedings, of which
one closed without ascertainment of any illicit behavior on the
part of Eni or its subsidiaries, while a further criminal proceeding
is still pending. The consultants appointed by the Court and those
designated by the plaintiffs performed a technical appraisal on
the matter, reaching very different outcomes. Thus, parties failed
to reach a settlement of the matter. On December 2015, the three
companies involved were sued in relation to a total of 30 cases of
compensation for damages in civil proceedings. The proceedings are
still pending. In May 2018, the Court issued a first instance judgment
concerning one case. The Judge rejected the claim for damages,
acknowledging the goodness and reasonableness of the arguments
of the defendant companies in relation to the absence of evidences
concerning the existence of a causal link between the pathologies
and the alleged industrial pollution. The first-degree sentence was
appealed before the Court of Caltanissetta.
(iv) Syndial – Environmental claim relating to the Municipality
of Cengio. The Ministry for the Environment and the Delegated
Commissioner for Environmental Emergency in the territory of
the Municipality of Cengio summoned Syndial before a Civil Court
and sentenced Eni’s subsidiary to compensate the environmental
damage relating to the site of Cengio. The request for environmental
damage amounted to €250 million to which add health damage to
be quantified during the proceeding. The plaintiffs accused Syndial
of negligence in performing the clean-up and remediation of the site.
In February 2013, the Court ruled a technical appraisal to verify the
existence of the environmental damage. Following failed attempts
to define a settlement agreement on the matter among the parties
involved, the Judge resumed the trial and requested an independent
appraisal on the matter. A first stage of the trial was filed in
September 2018. The proceeding is still at the preliminary stage.
(v) 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 Syndial and Versalis for the environmental
damage allegedly caused by carrying out illegal waste disposal
activities and unauthorized landfill. In particular, the plaintiff claimed
the responsibilities of Syndial and Versalis for the production of
waste and because they 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 (located about 2 kilometers away
from the town of Melilli). Two subsidiaries of Eni and a third-party
waste company were claimed to be jointly and severally liable
of 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 Syndial and Versalis, judging
the requests of the Municipality to be inadmissible for lack of locus
standi and considering the requests as unfounded or unproved, and
sentenced the Municipality to the reimbursement of the expenses
of the proceeding. In September 2017, the Municipality appealed
the ruling requesting a new investigation and the admission of a
technical appraisal, as well as the suspension of the enforcement
of the sentence of first instance. The Court of Appeal rejected the
counterclaim filed by the Municipality, which then filed an appeal
before a third-degree Court to obtain the repeal of the part of
the sentence about the expenses of the judgement, where Eni’s
subsidiaries are part. Furthermore, the Municipality filed an appeal
to overturn the first-degree sentence before another Court in Sicily,
where the Eni’s subsidiaries are planning to take part.
2. Court inquiries
(i) Eni SpA – Reorganization procedure of Alitalia Linee Aeree
Italiane SpA under extraordinary administration. On January
2013, the Italian airline company Alitalia, which was undergoing
a reorganization procedure, summoned Eni, Exxon Italia and
Kuwait Petroleum Italia SpA before the Court of Rome, to obtain a
compensation for alleged damages caused by a presumed 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 deliberation filed by the Italian Antitrust Authority
in June 2006. The antitrust deliberation accused Eni and other 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. The antitrust findings were
substantially endorsed by an administrative Court. Alitalia has made
a claim against the three petroleum companies jointly and severally
presenting two alternative ways to assess the alleged damages. A
first assessment of the overall damages amounted to €908 million.
This was based on the presumption that the anti-competitive
agreements among the defendants would have prevented Alitalia
from autonomously purchasing supplies of jet fuel in the years when
the existence of the anti-competitive agreements were ascertained
by the Italian Antitrust Authority and in subsequent years until Alitalia
ceased to operate airline activity. Alitalia asserted the incurrence
of higher supply costs of jet fuel of €777 million excluding interest
accrued and other items that add to lower profitability caused by a
reduced competitive position in the marketplace estimated at €131
million. Another assessment of the overall damage made by Alitalia
stand at €395 million of which €334 million of higher purchase costs
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for jet fuel and €61 million of lower profitability due to the reduced
competitive position on the marketplace. With a decision dated May
2014, the Court of Rome declared the connection with a judgment
previously proposed by Alitalia itself before the Court of Milan against
other oil companies participating to an alleged cartel agreement.
The case was thus summed up by Alitalia before the Court of Milan.
In September 2017, the Court of Milan ruled that: (i) the requests of
Alitalia for the period 1998-2004 were prescribed; (ii) for the period
subsequent to June 2006, no further assessment should be carried
out, since Alitalia has failed to meet its burden of allegation; (iii)
for the period between December 2004 and June 2006, a specific
technical appraisal will be carried out. The judgment is pending in
the first instance at the preliminary stage awaiting the fulfillment of
the technical appraisal. Eni accrued a provision with respect to this
proceeding.
(ii) 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 now claims an additional amount to be paid by Eni which
corresponds to the difference between the provisional price and
the contractual price. Eni, relying also on the opinion of its external
consultants, does not agree with GasTerra’s interpretation and
considers 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 (which at the time of the seizure
i.e. at the reporting date June 30, 2016, stated consolidated net
assets of €34.7 billion) 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. This
guarantee is expected to remain effective until a final award by
the arbitration procedure. The measure, which was granted after
a summary review only and without Eni being heard, does not
prejudice the outcome on the merits of the claims. The correct
interpretation of the arbitration award and the 2012-2015 price
revision will be subject to a new arbitration procedure.
3. Proceedings concerning criminal/administrative corporate
responsibility
(i) EniPower SpA. In June 2004, the Public Prosecutor of Milan
commenced inquiries into contracts awarded by Eni’s subsidiary
EniPower and on supplies from other companies to EniPower. It
emerged that illicit payments were made by EniPower suppliers to a
manager of EniPower who was immediately fired. The Court served
EniPower (the commissioning entity) and Snamprogetti (now Saipem
SpA) (contractor of engineering and procurement services) with
notices of investigation in accordance with Legislative Decree No.
231/01 that establishes that the companies are liable for the crimes
committed by their employees who acted on behalf of the employer.
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 under the provisions
of Legislative Decree No. 231/01. Eni SpA, EniPower and Snamprogetti
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 individuals. In relation to the companies involved in
the proceeding, the Court found that 7 companies are liable based
on the provisions of Legislative Decree No. 231/01, imposing a fine
and the disgorgement of profit. Eni SpA and its subsidiaries, EniPower
and Saipem, which took over Snamprogetti, acted as plaintiffs in the
proceeding also against the mentioned companies. 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 Supreme Court that stated the
illegitimacy of the constitution as plaintiffs against any legal entity,
as indicted under the provisions of Legislative Decree No. 231/01.
The condemned 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. In 2015, the
Supreme Court annulled the judgment of the Second Degree 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 February 2011, Eni received from the Public Prosecutor of Milan
an information request pursuant to 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 and Sonatrach relating to the construction of the GK3 gas
pipeline and the contract between Galsi, Saipem and Technip relating
to the engineering of the ground section of a gas pipeline). The crime
of international corruption is among the offenses contemplated
by the Italian 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 in
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accordance with 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, 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 in accordance with
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. During 2013, 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 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
and the Chief Upstream Officer of Eni 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 and Saipem on the basis of the provisions of Legislative Decree
No. 231/01) in connection with the entry into intermediary contracts
by Saipem in Algeria. Furthermore, some of the defendants (including
the former CEO and CFO of Eni and the Chief Upstream Officer of Eni)
were accused of tax offenses for alleged fraudulent misrepresentation
in relation to the accounting treatment of these contracts for the fiscal
years 2009 and 2010. After receiving (i) the evidence collected in
connection with the Public Prosecutor’s request to take testimony of
two individuals under investigation in late 2014, and (ii) the minutes
of the preliminary hearing and the documents filed in connection with
the conclusion of the preliminary investigation, Eni requested that its
consultants perform additional analysis and investigation. As a result,
Eni’s consultants reaffirmed their conclusions previously reported to
the Company. In February 2015, the Public Prosecutor requested the
indictment of all the investigated persons for international corruption
as well as the tax offenses mentioned above. In 2015, the Judge for
the Preliminary Hearing of the Court of Milan dismissed the case and
granted an acquittal in favor of Eni, former Chief Executive Officer
and Chief Upstream Officer for all the alleged offenses. In February
2016, the Court of Third Instance, upholding an appeal presented by
the Public Prosecutor, reversed the dismissal, annulled the verdict,
and remanded the proceedings to another Judge for the Preliminary
Hearing in the Court of Milan. As a result of the new preliminary
hearing in July 2016, the Judge ordered the trial for all defendants,
including Eni. Trial began in February 2017. At a hearing ion February
26, 2018, the Public Prosecutor, concluding his indictment, requested
— among other things — the imposition on Eni of a pecuniary
sanction. In September 2018, the Court of Milan rejected the requests
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 the MLE Project. In December 2018
the Court filed a written opinion setting forth the basis for its rulings.
The Public Prosecutor and the other parties who were convicted in the
first trial have appealed under the terms of the law. A hearing on those
appeals is pending.
At the end of 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. Following Eni’s notification in
2012, 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.
(iii) Block OPL 245 – Nigeria. In July 2014, the Public Prosecutor of
Milan served Eni with a notice of investigation relating to potential
liability on the part of Eni arising from alleged international
corruption, pursuant to Italian Legislative Decree No. 231/2001
whereby companies are liable for the crimes committed by
their employees when performing their tasks. As part of the
investigation, Eni was also subpoenaed for documents and
other evidence. According to the subpoena, the proceeding was
commenced following a claim filed by NGO ReCommon relating to
alleged corruptive practices that according to the Public Prosecutor
allegedly involved the Resolution Agreement made on April 29, 2011
relating to the Oil Prospecting License of the offshore oilfield that
was discovered in Block 245 in Nigeria. 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 in summary that they detected no evidence of
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212
wrongdoing by Eni side in relation to the 2011 transaction with the
Nigerian government for the acquisition of the OPL 245 license. The
outcome of this review was transmitted to the Judicial Authorities.
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. 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 the indictment of Eni’s CEO, the Chief Development,
Operations and Technological Officer and the Executive Vice
President for international negotiations, as well as Eni’s former
CEO and Eni based on Italian law 231/2001 on corporate entity
responsibility. 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 documentations
available did not alter the outcome of the prior review. 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. During the first trial hearing in March 2018, the the Federal
Republic of Nigeria requested permission to join the case as a civil
party. Several NGOs, which had made the same request before the
Judge of the Preliminary Hearing and been denied, also asked to
join as civil parties. At a hearing in May 2018, a Non-Governmental
Organization, Asso Consum, also requested to be recognized as
a civil claimant in the proceeding. At the subsequent hearing in
June 2018, counsel for the Federal Government of Nigeria (“FGN”)
reiterated the request for the admission as civil claimants in the
proceedings of all the parties that sought leave to join the action
as civil claimants in March 2018. At the same time, the attorney
requested that Eni and Shell be recognized as defendants with
respect to those parties’ civil claims. Furthermore, a shareholder
of Eni asked to be recognized as a civil claimant. At the hearing of
July 20, 2018, the Judge (i) granted the FGN’s request to join the
proceeding as a civil claimant and (ii) rejected that request with
respect to the NGOs, Asso Consum and the shareholder of Eni.
Therefore, the FGN is the only civil party admitted by the Court. 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. Eni has provided a copy
of the Order and the attached documents, including the charges filed
by the EFCC, to the US-based law firm engaged to review the OPL 245
transaction, who upon review of such documents, did not modify
their conclusion that they did not detect evidence of wrongdoing
by Eni in relation to the acquisition of the OPL 245 from the Nigerian
government. 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 the damages allegedly
deriving from the transaction that resulted in assignment of the
OPL 245 to NAE and SNEPCO (Shell subsidiary). Subsequently, Eni
obtained a copy of the documentation reflecting the commencement
of the case, but neither Eni nor other companies of the Group received
any notification regarding this proceeding.
(iv) Congo. In March 2017, the Italian Finance Police served on Eni
an information request pursuant to the Italian Code of Criminal
Procedure 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 Italian 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). On January 26, 2018, the Public Prosecutor’s Office
requested a six-months extension of the deadline for conducting its
preliminary investigation into this matter, from January 31, 2018
until July 30, 2018. Subsequently in July 2018, the Public Prosecutor
requested a second extension until February 28, 2019. In April 2018,
the Public Prosecutor of Milan served on Eni SpA 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 manager had been placed under
investigation. In October 2018, Public Prosecutor ordered the seizure
of an e-mail account of another Eni manager, who was formerly the
general director of Eni in Congo during the period 2010-2013.
In December 2018, the Public Prosecutor of Milan issued a request
to the Company for documents pursuant to article 248 of the Code
of Criminal Procedure, concerning some economic transactions
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213
between Eni Group companies and certain companies. In February
2019, Eni received an informative note that the preliminary
investigations would extend until October 2019.
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,
knowleadgeable in the matter of anti-corruption, to carry out a
forensic review of facts relating to Eni’s work in Congo. Based
on the preliminary results of such review, that is still on-going,
there were no factual evidence about the involvement of Eni, nor
of any Eni’s employees and key managers in the alleged crimes.
On June 4, 2018, the Italian market regulator, Consob, requested
information about the above mentioned proceeding from Eni
and its Board of Statutory Auditors. Specifically, Eni was asked
to provide information about the Congo investigations and the
action implemented by the Company and any eventual outcome,
including specific audit activities performed by the Company’s
staff and any task assigned to external parties to review the
ongoing investigations. The Company was also asked to transmit
supporting evidence and documentation. The Eni Board of
Statutory Auditors was asked to report about the monitoring
activity performed on the investigations. The Company and
its Board of Statutory Auditors answered these requests for
information on June 11 and 13, 2018, respectively.
4. 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 the 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 reunification
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. Eni collaborated fully providing all the
required documentation. Such proceeding referred to quantities of oil
products sold by Eni, allegedly larger than the quantity subjected to
the excise tax. After the end of the investigation, the financial police
of Frosinone, along with the local Customs Agency, in November 2013
issued a claim related to the missing payment of excise taxes in the
2007-2012 period for €1.55 million. In May 2014, the Customs Agency
of Rome issued a payment notice relating to the abovementioned
claim that was filed by the financial police and Customs Agency of
Frosinone. The Company appealed to the Tributary Commission. In
March 2018, the Commission filed the ruling of the sentence which
accepted Eni’s appeal against the claim of the Custom Agency
and required the latter to refund the proceeding expenses; (ii) a
second proceeding, concerning a line of investigation of the Public
Prosecutor’s Office of Prato, commenced in regard to the deposit of
Calenzano and relates to subtraction 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, regarded 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 subjected
to verification. The second and the third proceeding were merged
in the proceeding commenced by Public Prosecutor’s Office of
Rome. In fact, the Public Prosecutor’s Office of Rome has alleged the
existence of a criminal conspiracy aimed at habitual subtraction of
oil products at all of the 22 storage sites which are operated by Eni
over the national territory. Eni is cooperating with the Prosecutor in
order to defend the correctness of its operation. On 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
relates to a period of time when the officer was in charge at Eni’s
R&M Division. On 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. In November 2017, the Court of Rome, following
the request of the Public Prosecutor, ordered a preventive seizure
of the oil products meters at Eni’s refineries and depots in Italy. The
Company, considering the consequences connected to a complete
shutdown of the refining and fueling activities, requested the
Public Prosecutor to minimize, as much as possible, the impact on
customers, companies and service stations. The preventive seizure
was revoked, due to the commitments undertaken by the Company
which is a third party not subject to investigation. Eni continues
to provide full cooperation to the authorities. In December 2017,
technical consultants were designed by Eni to verify the integrity
of the sites. The results will be provided to the judicial authorities. In
March 2018, the Public Prosecutor of Rome notified the conclusion of
the preliminary investigations in relation to the criminal proceeding
No. 7320/2014 concerning the Calenzano, Livorno, Sannazzaro,
Pomezia, Naples, Gaeta and Ortona sites. Based on the outcome of
the investigations, as far as Eni is concerned, the proceeding involves
former managers and directors of the 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. In addition for Calenzano, three
employees and their manager of the storage site were indicted on
charges of alleged procedural fraud. The attorneys of the defendants
delivered documentations and requested the Public Prosecutor to
dismiss the case.
In September 2018, Eni received, as offended 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 –
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018
214
subject of a separated proceeding (No. 22066/17 RGNR), for which,
in May 2017, the Public Prosecutor’s Office had requested the filing.
At the end of the hearing in December 2018, the Judge accepted
the request for dismissal for several persons under investigation,
including thirteen Eni’s employees, while he rejected the request,
requiring the Public Prosecutor to pronounce the charge in terms
and forms of law for twenty-eight Eni employees (including the
former managers of the R&M Division) for criminal association. In
October 2018, as regards the main criminal proceeding, the Public
Prosecutor notified the date for the preliminary hearing and the
related request for indictment.
In April 2018 as part of the administrative proceeding intended
to collect taxes allegedly not paid 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 litigation, for which
omitted payment is disputed, relates to the same transactions
successfully challenged by the Company against the Tax
Commission of Rome. The Company will appeal at the appropriate
forum. Eni accrued a provision with respect to this proceeding.
(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, the former Chief Legal and Regulatory
Affairs Officer of Eni, currently the Chief Gas & LNG Marketing
and Power Officer of the Company. Eni is not under investigation.
According to the decree, the association would be 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 auditing firm
to perform an internal audit of all relevant facts and circumstances
and all records and documentation on 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 would be no sufficient factual evidence about the
involvement of the former Chief Legal manager and Regulatory
Affairs manager of Eni in the alleged crimes.
In 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.
The outcomes illustrated in two reports, dated November 22, 2018
and February 14, 2019, did not highlight circumstances in fact
suitable any direct involvement of any Eni’s employees in the crimes
alleged by the Public Prosecutor. Both reports were presented to the
Board of Directors, to the Board of Statutory Auditors and to the Watch
Structure of Eni.
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 the external auditor regarding the matter and to keep Consob
updated about any further initiative adopted. The Company and its
Board of Statutory Auditors answered the request of information
on June 11 and June 13, 2018, respectively. Subsequently, the
Company finalized its response by sending further documentation
including the final report of the audit firm and the reports of the
consultants.The Board of Statutory Auditors has periodically
updated Consob of the initiatives taken as part of the Board’s
monitoring responsibilities with communications transmitted on
September 21, December 3 and 20, 2018 and on February 19, 2019.
On June 13, 2018, Eni was notified of a request from the Prosecutor
Office to transmitting certain documentation in accordance with the
provision of the Italian penal code. The request targeted evidence
and documents relating to the internal audit performed by the
Company and any possible external review concerning certain
tasks that were assigned to an external lawyer with respect to Eni.
This lawyer appears to be investigated as part of this proceeding.
The reports of the consultants of the Board of Directors and of the
independent third party were sent to the Judicial Authority.
(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.
5. Settled Proceedings
(i) Syndial SpA – Clorosoda. The proceeding, involving 17 former
managers of the Eni Group, regards alleged crimes of culpable
manslaughter and grievous bodily harm related to the death of
12 former employees and alleged work-related diseases that
those persons may have contracted at the plant of Clorosoda.
Alleged crimes relate to the period from 1969, when the
Clorosoda plant commenced operations, until 1998 when the
plant was shut down and clean-up activities were performed.
The Public Prosecutor requested a medical appraisal on over
100 people who had been employed at the plant. This appraisal
was performed by independent consultants designated by the
Judge for preliminary investigation and did not find any evidence
that the various diseases identified from the medical appraisal
could be directly linked to the exposure to emissions related
to the production of chlorine and caustic soda. The consultants
also found that production activities were in compliance with
applicable laws and regulations on health and safety. Following
the outcome of the assessment, the Public Prosecutor of Gela
issued a notice of conclusion of preliminary investigations in
relation to 4 cases, contesting personal injuries and claimed the
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
215
indictment only in one case concerning a worker who died in the
meantime. Therefore, compared to the initial claim that concerned
several (more than one hundred) cases of personal injury and
manslaughter, the proceeding was narrowed. In June 2017, the
Judge issued a ruling of nonsuit because the case was judged
groundless. The Public Prosecutor appealed the first-degree
sentence. In September 2018, the Second Instance Court in its
final decision did not accept the appeal presented by the Public
Prosecutor. Also for the proceeding concerning the four cases that
are part of a separate proceeding, the Judge issued a ruling of
nonsuit, which became irrevocable in February 2018.
(ii) Eni SpA – Raffineria di Gela SpA – Eni Mediterranea Idrocarburi
SpA - Syndial SpA. In December 2015, 273 Gela residents filed an
appeal to the Court of Gela requesting to halt all the production
activities conducted by Eni’s subsidiaries at Gela site in order
to put an end to alleged environmental pollution affecting the
health of the local population. The claimants also requested the
appointment of commissioners in charge of carrying out the plant
shutdown and of continuing implementing of clean-up activities in
the area. They also requested the Court to order the Municipality
of Gela – as a competent body in the field of health protection
– to adopt certain provisions aimed to preserve the health of
the local population. This proceeding arose in connection with
alleged environmental damage caused by the industrial activities
of the site and consequent necessity to protect the population
from serious harm to the health. The initiative was carried out
by certain technical assessments performed by consultants
appointed by the Court in the preliminary stage. The aim of these
assessments was to establish cause-and-effect relationships
between the industrial contamination and congenital anomalies
reported in the town of Gela. Following the outcome of the
investigation, in December 2017 the Court of Gela rejected all the
claims of the plaintiffs and ordered them to pay the expenses of
the proceeding. The plaintiffs appealed the decision. In September
2018, the Court rejected the appeal presented by the appellants,
confirming the order issued by the First Instance Court. The
precautionary procedure promoted is therefore definitively
concluded.
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
concession, 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 2018, 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 19.93 million tonnes, Eni was awarded
free emission allowances of 7.25 million tonnes, determining a deficit
of 12.68 million tonnes. This deficit was entirely covered through the
purchase of emission allowances in the open market.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 216
28 | Revenues
NET SALES FROM OPERATIONS
(€ million)
2018
Revenues from customers
Products sales and service revenues
Sales of:
- crude oil
- oil products
- natural gas and LNG
- chemical products
- other products
Services
Total
Transfer of goods and/or services
Goods/Services transferred in a specific moment
Goods/Services transferred over a period of time
Exploration
& Production
Gas
& Power
Refining &
Marketing and
Chemicals
Corporate
and other
activities
Total
9,943
43,109
22,594
176
75,822
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
17,213
4,777
20
584
22,594
42,979
130
22,535
59
35
11
130
176
106
70
22,453
22,399
19,642
5,574
2,421
3,333
75,822
75,296
526
2018
342
11
(€ million)
Revenues associated with liabilities from customer contracts at the beginning of the period
Revenues associated with performance obligations totally or partially satisfied in previous years
Sales from operations by industry segment and geographical area
of destination are disclosed in note 35 – Segment information and
information by geographical area.
Sales from operations with related parties are disclosed in note 36
– Transactions with related parties.
OTHER INCOME AND REVENUES
(€ million)
Gains from sale of assets and businesses
Other proceeds
2018
454
662
1,116
2017
3.288
770
4,058
2016
14
917
931
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 million 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 income and revenues with related parties are disclosed in
note 36 – Transactions with related parties.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 29 | Costs
PURCHASE, SERVICES AND OTHER
(€ million)
Production costs - raw, ancillary and consumable materials and goods
Production costs - services
Operating leases and other
Net provisions for contingencies
Expenses 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
217
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
2016
27,783
12,727
1,672
505
240
666
43,593
(297)
(18)
43,278
Purchase, services and other charges include costs of geological and
geophysical studies for €287 million (€273 million and €204 million
in 2017 and 2016, respectively) and operating leases for €872 million
(€1,022 million and €566 million in 2017 and 2016, 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 €197 million (€185 million and €161 million in 2017 and 2016,
respectively).
Royalties on the extraction of hydrocarbons amounted to
€1,043 million (€674 million and €572 million in 2017 and 2016,
respectively).
Future minimum lease payments expected to be paid under non-
cancelable operating leases are provided below:
(€ million)
To be paid:
- within 1 year
- between 2 and 5 years
- beyond 5 years
2018
2017
2016
776
1,653
1,524
3,953
883
1,710
1,939
4,532
593
1,040
785
2,418
Operating leases primarily comprised long-term rentals of FPSO
vessels, offshore drilling rigs, time charter and land, service stations
and office buildings. Such leases may not include renewal options.
There are no significant restrictions provided by these operating
leases that may limit the ability of Eni to pay dividends, use assets
or take on new borrowing.
Additions to provisions for contingencies net of reversal of unused
provisions related to net additions for litigations amounting to €101
million (net additions of €375 million and €55 million in 2017 and
2016, respectively) and net additions for environmental liabilities
amounting to €266 million (net additions of €200 million and
€198 million in 2017 and 2016, respectively). More information
is provided in note 20 – Provisions for contingencies. Provisions
for contingencies by segment are disclosed in note 35 – Segment
information and information by geographical area.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 218
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
2018
2,409
448
220
170
3,247
(142)
(12)
3,093
2017
2,447
441
113
162
3,163
(202)
(10)
2,951
2016
2,491
445
81
202
3,219
(215)
(10)
2,994
Other costs comprised provisions for redundancy incentives of €37
million (€18 million and €47 million in 2017 and 2016, respectively)
and costs for defined contribution plans of €95 million (€90 million
and €83 million in 2017 and 2016, 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's average number and breakdown of employees by category is reported below:
(number)
Senior managers
Junior managers
Employees
Workers
2018
2017
2016
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
Subsidiaries
1,018
9,160
17,180
5,703
33,061
Joint
operations
18
109
384
294
805
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 interest 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 service 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”)29 and the TSR of their
corresponding stock exchange market30; (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.
At the grant date, the number of shares awarded was 1,517,975
and 1,719,061 respectively in 2018 and in 2017; the weighted
average fair value of the shares at the same date was €11.73
and €7.99 per share.
(29) The group consists of the following oil companies: Anadarko, Apache, BP, Chevron, ConocoPhillips, ExxonMobil, Marathon Oil, Royal Dutch Shell, Statoil and Total.
(30) The performance condition connected with the TSR in accordance with the international accounting standards represents a so-called market condition.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 219
The determination 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 (€14.246 per share
in 2018; €13.81 per share in 2017), reduced by dividends expected
along the vesting period (5.8% of the share price at vesting date), the
volatility of the stock (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 2018, the costs related to the long-term monetary incentive plan
2017-2019, recognized as a component of the payroll cost, amounted
to €5.1 million (€0.4 million in 2017) with a contra-entry to equity
reserves.
Compensation of key management personnel
Compensation (including contributions and ancillary costs)
of personnel holding key positions in planning, directing and
controlling Eni Group's subsidiaries, including executive and non-
executive officers, general managers and managers with strategic
responsibilities in service during the year consisted of the following:
(€ million)
Wages and salaries
Post-employment benefits
Other long-term benefits
Indemnities upon termination of employment
2018
27
2
10
39
2017
25
2
9
7
43
2016
26
2
12
4
44
Compensation of Directors and Statutory Auditors
Compensation of Directors amounted to €9.6 million, €14.5 million
and €7.1 million for 2018, 2017 and 2016, respectively. Compensation
of Statutory Auditors amounted to €0.604 million, €0.760 million and
€0.738 million in 2018, 2017 and 2016, 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 due to banks and other financial institutions
- Interest and other income on financial receivables and securities held for non-operating purposes
- Interest from banks
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.
2018
2017
2016
3,967
(4,663)
32
(307)
(971)
3,924
(5,886)
(111)
837
(1,236)
5,850
(6,232)
(21)
(482)
(885)
2018
2017
2016
(565)
32
(120)
8
18
(627)
341
(307)
132
52
(249)
(313)
(378)
(971)
(638)
(111)
(113)
16
12
(834)
(905)
837
128
73
(264)
(271)
(334)
(1,236)
(639)
(21)
(118)
37
15
(726)
676
(482)
143
106
(312)
(290)
(353)
(885)
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018 220
The analisys of derivative financial income (expense) 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.
31 | Income (expense) from investments
SHARE OF PROFIT (LOSS) OF EQUITY-ACCOUNTED INVESTMENTS
More information is provided in note 14 – Investments. Share of profit or loss of equity-accounted investments by segment is disclosed in
note 35 – Segment information and information by geographical area.
OTHER GAIN (LOSS) FROM INVESTMENTS
(€ million)
Dividends
Net gain (loss) on disposals
Other net income (expense)
2018
231
22
910
1,163
2017
205
163
(33)
335
2016
143
(14)
(183)
(54)
Dividend income related to Nigeria LNG Ltd for €187 million and to
Saudi European Petrochemical Co for €35 million (similarly in the
comparative periods).
Other net income included the gain of €889 million deriving from the
business combination between Eni Norge AS and Point Resources
AS, fully-owned respectively by Eni and HitecVision AS, with the
establishment of the joint venture Vår Energi AS, jointly controlled by
the two shareholders and was determined as difference between the
carrying amount of the equity investment, corresponding to the fair
value of the combined net assets, and the book value of the divested
net assets. In the comparative periods the expenses referred to the
impairments of joint ventures and associates.
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
2018
2017
2016
301
4,906
163
5,370
130
497
(27)
600
5,970
712
3,167
142
4,021
(464)
(162)
72
(554)
3,467
195
2,671
133
2,999
(243)
(813)
(7)
(1.063)
1,936
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 221
Current income taxes payable by Italian subsidiaries referred to
foreign taxes for €241 million.
The reconciliation between the statutory tax charge calculated
by applying the Italian statutory tax rate of 24% (24% in 2017 and
27.5% in 2016) 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-off of deferred tax assets and recalculation of tax rates
- effect due to the tax regime provided for intercompany dividends
- Italian regional income tax (IRAP)
- effect due to non-taxable gains/losses on sales of investments
- impact pursuant to redetermination of the Italian Windfall Corporate tax as per Law 7/2009
- other adjustments
Effective tax charge
2018
10,107
24.0
2,426
3,096
252
47
50
(1)
100
3,544
5,970
2017
6,844
24.0
1,643
1,882
(96)
1
77
(177)
61
76
1,824
3,467
2016
892
27.5
245
1,152
397
87
42
8
5
1,691
1,936
The higher tax charges at non-Italian subsidiaries related to the Exploration & Production segment for €3,014 million (€1,811 million and
€1,211 million in 2017 and in 2016, 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 2018 was 3,601,140,133 (same amount in
2017 and 2016).
Diluted earnings per share is calculated by dividing the net profit of the
period attributable to Eni’s shareholders by the weighted average number
of shares fully-diluted including shares outstanding in the year and the
number of potential shares to be issued in connection with stock-based
compensation plans.
As of December 31, 2018, the shares that could be potentially issued
related the estimation of new share that will vest in connection with the
long-term monetary incentive plan. The weighted average number of
outstanding shares used for calculating the diluted earnings per share is
2,782,584 for 2018 (1,691,413 for 2017). In 2016, there were no potential
shares with dilutive effects.
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 the calculation
of the basic earnings per share
Potential share to be issued for ILT incentive plan
Weighted average number of shares used for the calculation
of the diluted earnings per share
Eni’s net profit
Basic earning (loss) per share
Diluted earning (loss) per share
Eni’s net profit - Continuing operations
Basic earning (loss) per share
Diluted earning (loss) per share
Eni’s net profit - Discontinued operations
Basic earning (loss) per share
Diluted earning (loss) per share
2018
2017
2016
3,601,140,133
3,601,140,133
3,601,140,133
2,782,584
1,691,413
3,603,922,717
3,602,831,546
3,601,140,133
4,126
1.15
1.15
4,126
1.15
1.15
3,374
0.94
0.94
3,374
0.94
0.94
(1,464)
(0.41)
(0.41)
(1,051)
(0.29)
(0.29)
(413)
(0.12)
(0.12)
(€ million)
(euro per share)
(euro per share)
(€ million)
(euro per share)
(euro per share)
(€ million)
(euro per share)
(euro per share)
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018
222
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
35 | Segment information and information by geographical area
SEGMENT INFORMATION
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
2016
4
170
204
374
1,092
1,905
2,997
118
417
204
621
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, 2018, Eni had the following reportable segments:
Exploration & Production: engages in the exploration, development
and production of crude oil, LNG and natural gas, including projects to
build and operate liquefaction plants of natural gas.
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 engaged in supply and marketing of crude oil and
oil products targeting the operational requirements of Eni’s refining
business and in commodity trading (including crude oil, natural gas,
oil products, power, emission allowances, etc.) targeting to both hedge
and stabilize the Group 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, planning and administration activities,
as well as the results of the Group environmental cleanup and
remediation activities performed by the subsidiary Syndial. The Energy
Solutions Department, which engages in developing the business of
renewable energy, is an operating segment, which is reported within
Corporate and other activities because it does not meet the materiality
threshold for separate segment reporting.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 223
n
o
i
t
c
u
d
o
r
P
&
n
o
i
t
a
r
o
l
p
x
E
25,744
(15,801)
9,943
10,214
235
6,152
1,025
299
97
158
63,051
r
e
w
o
P
&
s
a
G
55,690
(12,581)
43,109
629
53
408
56
127
1
9
9,989
4,972
18,110
494
8,314
s
l
a
c
i
m
e
h
C
d
n
a
i
&
g
n
n
fi
e
R
g
n
i
t
e
k
r
a
M
25,216
(2,622)
22,594
(380)
274
399
193
2
(67)
11,692
275
4,319
s
e
i
t
i
v
i
t
c
a
r
e
h
t
o
d
n
a
e
t
a
r
o
p
r
o
C
1,589
(1,413)
176
(691)
579
59
18
(168)
1,171
1,303
4,072
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
211
(21)
(30)
(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
(101)
1,108
1,447
4,053
(27)
(29)
(610)
(306)
7,739
142
729
87
(16)
16,089
(9,711)
6,378
2,567
123
6,772
740
1,440
153
(198)
75,716
1,626
17,433
40,961
(8,898)
32,063
(391)
50
354
167
86
2
19
12,014
18,733
(1,605)
17,128
723
171
389
120
16
195
(3)
10,712
592
8,923
289
3,968
1,343
(1,150)
193
(681)
438
72
40
(144)
1,146
1,533
3,939
(61)
(277)
(28)
(520)
(332)
8,254
120
664
55
87
l
a
t
o
T
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
55,762
2,157
505
7,559
1,067
1,542
350
(326)
99,068
25,477
4,040
33,931
37,528
9,180
Information by segment is as follows:
(€ million)
2018
Net sales from operations(a)
Less: intersegment sales
Net sales to customers
Operating profit
Net provisions for contingencies
Depreciation and amortization
Impairments of tangible and intangible assets
Reversals of tangible and intangible assets
Write-off
Share of profit (loss) of equity-accounted investments
Identifiable assets(b)
Unallocated assets
Equity-accounted investments
Identifiable liabilities(c)
Unallocated liabilities
Capital expenditure in tangible and intangible assets
2017
Net sales from operations(a)
Less: intersegment sales
Net sales to customers
Operating profit
Net provisions for contingencies
Depreciation and amortization
Impairments of tangible and intangible assets
Reversals of tangible and intangible assets
Write-off
Share of profit (loss) of equity-accounted investments
Identifiable assets(b)
Unallocated assets
Equity-accounted investments
Identifiable liabilities(c)
Unallocated liabilities
Capital expenditure in tangible and intangible assets
2016
Net sales from operations(a)
Less: intersegment sales
Net sales to customers
Operating profit
Net provisions for contingencies
Depreciation and amortization
Impairments of tangible and intangible assets
Reversals of tangible and intangible assets
Write-off
Share of profit (loss) of equity-accounted investments
Identifiable assets(b)
Unallocated assets
Equity-accounted investments
Identifiable liabilities(c)
Unallocated liabilities
Capital expenditure in tangible and intangible assets
(a) Before elimination of intersegment sales.
(b) Includes assets directly associated with the generation of operating profit.
(c) Includes liabilities directly associated with the generation of operating profit.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018
224
FINANCIAL INFORMATION BY GEOGRAPHICAL AREA
Identifiable assets and investments by geographical area of origin.
(€ million)
2018
Identifiable assets(a)
Capital expenditure in tangible and intangible assets
2017
Identifiable assets(a)
Capital expenditure in tangible and intangible assets
2016
Identifiable assets(a)
Capital expenditure in tangible and intangible assets
(a) Includes assets directly associated with the generation of operating profit.
Net 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
7,086
267
7,706
316
7,370
331
e
p
o
r
u
E
f
o
t
s
e
R
1,031
538
6,160
387
6,960
460
s
a
c
i
r
e
m
A
4,546
534
4,406
278
5,397
233
l
y
a
t
I
18,646
1,424
18,449
1,090
18,769
1,163
a
i
s
A
a
c
i
r
f
A
16,910
1,782
36,155
4,533
16,527
898
35,385
5,699
s
a
e
r
a
r
e
h
t
O
1,109
41
1,183
13
l
a
t
o
T
85,483
9,119
89,816
8,681
19,471
1,978
39,812
5,004
1,289
11
99,068
9,180
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
2016
21,280
15,808
4,804
3,212
5,619
4,865
174
55,762
36 | Transactions with related parties
In the ordinary course of its business, Eni enters into transactions with
related parties regarding:
(a) exchange of goods, provision of services and financing with joint
ventures, associates and non-consolidated subsidiaries;
(b) exchange of goods and provision of services with entities
controlled by the Italian Government;
(c) exchange of goods and provision of services with 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 of Eni “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 under 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 lower than €1 million)
conducted with Vodafone Italia SpA related to Eni SpA through of a
member of the Board of Directors;
(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 in the fields of economics, energy and
environment, both at the national and international level.
Some low transactions with companies related to Eni SpA through
some members of the Board of Directors were concluded at market
or standard conditions, or in compliance with Eni’s internal procedure
“Transactions involving interests of Directors and Statutory Auditors
and transactions with related parties”, pursuant the Consob regulation.
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, 2018 are presented in the annex “List of companies
owned by Eni SpA as of December 31, 2018”. This annex includes also
the changes in the scope of consolidation.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
225
TRADE AND OTHER TRANSACTIONS WITH RELATED PARTIES
2018
Name
Joint ventures and associates
Agiba Petroleum Co
Angola LNG Supply Services Llc
Coral FLNG SA
Gas Distribution Company of Thessaloniki-Thessaly SA
Karachaganak Petroleum Operating BV
Mellitah Oil & Gas BV
Petrobel Belayim Petroleum Co
Saipem Group
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
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»
December 31, 2018
2018
Receivables
and other
assets
Payables
and other
liabilities Guarantees
(€ million)
Costs Revenues
Other
operating
(expense)
income
1
14
1
27
1
56
75
4
13
44
236
87
6
93
329
134
67
5
237
26
25
494
1
40
96
18
134
268
2,029
171
7
100
25
2,848
1
23
24
2,872
151
85
146
289
47
18
736
2
140
177
1,147
793
57
218
2,392
177
5
14
196
2,588
156
51
998
502
2,282
420
104
4,513
13
13
4,526
514
588
667
1,184
231
34
3,218
32
62
1
1
7
30
123
111
335
11
7
18
353
118
555
23
109
150
45
1,000
4
229
34
37
(26)
11
11
227
74
(1)
8
308
Total
864
3,750
2,588
8,005
1,391
319
(*) Each individual amount included herein was lower than €50 million.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018
226
2017
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
December 31, 2017
2017
Receivables
and other
assets
Payables
and other
liabilities Guarantees
(€ million)
Costs Revenues
Other
operating
(expense)
income
1
20
36
5
86
63
84
295
77
20
97
392
123
69
14
187
35
50
478
1
39
83
4
121
220
1,205
76
22
1,731
1
23
24
1,755
187
219
180
351
31
21
989
2
145
1,094
7,270
57
8,421
169
5
7
181
8,602
1
1
142
951
495
3,168
450
3
140
5,349
14
14
5,363
622
506
681
1,221
212
38
3,280
25
28
2
8
44
202
128
412
7
7
14
426
164
702
18
85
154
16
1,139
1
530
42
28
28
28
285
2
15
1
303
Groupement Sonatrach – Agip «GSA» and Organe Conjoint des Opérations «OC SH/FCP»
Total
910
2,891
8,603
9,198
1,608
331
(*) Each individual amount included herein was lower than €50 million.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
2016
Name
Joint ventures and associates
Agiba Petroleum Co
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
227
December 31, 2016
2016
Receivables
and other
assets
Payables
and other
liabilities Guarantees
(€ million)
Costs Revenues
Other
operating
(expense)
income
1
47
7
225
64
114
458
69
9
78
536
151
58
54
44
33
43
383
50
187
134
532
224
25
1,152
1
16
17
1,169
254
32
1
541
46
24
898
2
331
8,094
57
1
8,152
192
3
51
246
8,398
1
1
156
918
477
1,940
781
145
4,417
8
8
4,425
808
243
4
2,032
232
37
3,356
32
27
2
51
94
143
317
2
10
12
329
201
414
113
117
68
913
423
70
47
47
47
182
5
13
200
Groupement Sonatrach – Agip «GSA» and Organe Conjoint des Opérations «OC SH/FCP»
176
Total
1,095
2,400
8,399
8,236
1,312
247
(*) Each individual amount included herein was lower than €50 million.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018
228
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 oil products by
Eni Trading & Shipping SpA; services charged to Eni’s associates are
invoiced on the basis of incurred costs;
- guarantees issued on behalf of Angola LNG Supply Services Llc to cover
the commitments relating to the payment of the regasification fees;
- supply of upstream specialist services and guarantees 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 Gas
Distribution Company of Thessaloniki-Thessaly SA;
- engineering, construction and drilling services by Saipem Group
mainly for the Exploration & Production segment and the provision
of services and residual guarantees issued by Eni SpA relating to bid
bonds and performance bonds;
- performance guarantees given on behalf of Unión Fenosa Gas SA in
relation to contractual commitments related to the results of operations,
sales of LNG and fair value of derivative financial instruments;
- 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 the Snam Group and the Italgas Group on the basis of
tariffs set by the Italian Regulatory Authority for Energy, Networks
and Environment and purchase and sale of natural gas for granting
the balancing of the system on the basis of prices referred to the
quotations of the main energy commodities;
- sale and purchase of electricity, the acquisition of domestic
electricity transmission service 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 the Terna Group;
- sale and purchase of electricity, gas, environmental certificates, fair
value of derivative financial instruments and sale of oil products
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.
- guarantees issued in compliance with contractual agreements in the
interest of Vår Energi AS and trade and other receivables and payables;
- a guarantee issued in relation to the construction of an oil pipeline
Transactions with other related parties concerned:
- provisions to pension funds of €24 million; and
- contributions and service provisions to Eni Foundation of €3 million
on behalf of Eni BTC Ltd; and
and to Eni Enrico Mattei Foundation for €4 million.
FINANCING TRANSACTIONS WITH RELATED PARTIES
2018
(€ million)
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
December 31, 2018
2018
Receivables
Payables Guarantees
Charges
Gains
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
1,664
95
7
13
115
115
267
5
9
281
2
2
283
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
2017
(€ million)
Joint ventures and associates
Angola LNG Ltd
Cardón IV SA
Coral FLNG SA
Coral South FLNG D MCC
Saipem Group
Shatskmorneftegaz Sarl
Société Centrale Electrique du Congo SA
Other
Unconsolidated entities controlled by Eni
Servizi Fondo Bombole Metano SpA
Other(*)
Entities controlled by the Government
Other
Total
(*) Each individual amount included herein was lower than €50 million.
2016
(€ million)
Joint ventures and associates
Cardón IV SA
Matrìca SpA
Shatskmorneftegaz Sarl
Société Centrale Electrique du Congo SA
Unión Fenosa Gas SA
Saipem Group
Other(*)
Unconsolidated entities controlled by Eni
Eni BTC Ltd
Other(*)
Entities controlled by the Government
Other
229
December 31, 2017
2017
Receivables
Payables Guarantees
Charges
Gains
955
56
101
66
48
1,226
60
1
61
1,287
233
1,334
56
2
1,625
1,625
3
43
49
95
9
52
61
8
8
164
86
71
13
6
14
190
1
1
191
1
1
3
3
4
December 31, 2016
2016
Receivables
Payables Guarantees
Charges
Gains
Derivative
financial
instruments
1,054
125
69
78
52
1,378
46
46
82
2
84
85
85
54
52
106
93
13
18
17
141
1
1
3
3
145
96
9
4
43
4
156
1
1
27
27
157
27
Total
1,424
191
84
(*) Each individual amount included herein was lower than €50 million.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018
230
The most significant transactions with joint ventures, associates and
unconsolidated subsidiaries concerned:
- bank debt guarantees issued on behalf of Angola LNG Ltd;
- financing loans granted to Cardón IV SA for the exploration and
development activities of the Perla offshore gas field in Venezuela;
- a cash deposit held at Eni’s financial companies by Vår Energi AS.
The most significant transactions with entities controlled by the Italian
Government concerned:
- restricted deposits in escrow of derivative financial instruments
- financing loans granted to Coral FLNG SA for the construction
with Enel Group.
of a floating gas liquefaction plant in the Area 4 in Mozambique (for
more information see note 27 – Guarantees, commitments and risks);
- a bank debt guarantee issued on behalf of Coral South FLNG DMCC (for
more information see note 27 – Guarantees, commitments and risks);
- the impairment of financial receivables granted to
Shatskmorneftegaz Sàrl;
- the loan granted to Société Centrale Electrique du Congo SA for the
construction of a power plant in Congo and a cash deposit at Eni’s
financial companies;
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 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
Trade and other payables
Other current liabilities
Other non-current liabilities
December 31, 2018
December 31, 2017
s
e
i
t
r
a
p
d
e
t
a
l
e
R
49
633
71
915
160
661
3,664
63
23
l
a
t
o
T
300
14,101
2,258
1,253
792
2,182
16,747
3,980
1,502
%
t
c
a
p
m
I
16.33
4.49
3.14
73.02
20.20
30.29
21.88
1.58
1.53
l
a
t
o
T
316
15,421
1,573
1,675
1,323
2,242
16,748
1,515
1,479
s
e
i
t
r
a
p
d
e
t
a
e
R
l
73
834
30
1,214
46
164
2,808
60
23
The impact of transactions with related parties on the profit and loss accounts consisted of the following:
2018
2017
2016
s
e
i
t
r
a
p
d
e
t
a
l
e
R
l
a
t
o
T
%
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
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)
2.34
1.01
17.78
55,762
931
(43,278)
1,238
74
(8,212)
(415)
(3,093)
129
3,967
(4,663)
(307)
26
(22)
319
115
(283)
..
(913)
0.71
..
2.90
6.07
(2,951)
(32)
3,924
(5,886)
837
(34)
331
191
(4)
1.15
..
4.87
0.07
(846)
(2,994)
16
5,850
(6,232)
(482)
(24)
247
157
(145)
27
(€ million)
Net 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
Derivative financial instruments
%
t
c
a
p
m
I
23,10
5.41
1.91
72.48
3.48
7.31
16.77
3.96
1.56
%
t
c
a
p
m
I
2.22
7.95
18.97
0.80
..
2.69
2.33
..
CONSOLIDATED FINANCIAL STATEMENTS 2018 | 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 (loss)
Net change in trade and other receivables and liabilities
Net interests
Net cash provided from operating activities
Capital expenditure in tangible and intangible assets
Disposal of investments
Net change in accounts payable and receivable in relation to investments
Change in financial receivables
Net cash used in investing activities
Change in financial 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:
231
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)
2016
1,312
(5,623)
247
182
133
(3,749)
(2,613)
463
252
5,650
3,752
(192)
(192)
(189)
2018
2017
2016
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
(2,707)
(3,314)
16
..
43.98
..
10,117
(3,768)
(4,595)
(2,843)
(3,115)
(16)
..
82.67
0.35
7,673
(4,443)
(3,651)
(3,749)
3,752
(192)
l
a
t
o
T
13,647
(7,536)
(2,637)
%
t
c
a
p
m
I
..
..
5.26
(€ million)
Cash provided from operating activities
Cash used in investing activities
Cash used in financing activities
37 | Other information about investments31
Information on Eni’s consolidated subsidiaries with
significant non-controlling interest
Changes in the ownership interest without loss of
control
In 2018 and 2017, Eni did not own any consolidated subsidiaries with a
significant non-controlling interest.
Total shareholders’ equity pertaining to minority interests as of
December 31, 2018, amounted to €57 million (€49 million December
31, 2017).
In 2018 and 2017, Eni did not report any changes in ownership interest
without loss or acquisition of control.
(31) Investments in subsidiaries, joint arrangements and associates as of December 31, 2018 are presented in the annex “List of companies owned by Eni SpA as of December 31, 2018”. This annex
includes also the changes in the scope of consolidation.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018
232
Principal joint ventures, joint operations and associates as of December 31, 2018
Company name
Joint Venture
Gas Distribution Company
of Thessaloniki-Thessaly SA
Saipem SpA
Unión Fenosa Gas SA
Vår Energi AS
Joint operation
GreenStream BV
Mozambique Rovuma Venture SpA
Raffineria di Milazzo ScpA
Associates
Angola LNG Ltd
Coral FLNG SA
Registered office
Country
of operation
Business
segment
% ownership
interest
% voting
rights
Ampelokipi-Menemeni
(Greece)
San Donato Milanese (MI)
(Italy)
Madrid
(Spain)
Forus
(Norway)
Amsterdam
(Netherlands)
San Donato Milanese (MI)
(Italy)
Milazzo (ME)
(Italy)
Hamilton
(Bermuda)
Maputo
(Mozambique)
Greece
Italy
Spain
Gas & Power
Other Activities
Gas & Power
Norway
Exploration & Production
Lybia
Gas & Power
Mozambique
Exploration & Production
Italy
Refining & Marketing
Angola
Exploration & Production
Mozambique
Exploration & Production
49.00
30.54
50.00
69.60
50.00
35.71
50.00
13.60
25.00
49.00
30.99
50.00
69.60
50.00
35.71
50.00
13.60
25.00
The 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:
2018
(€ 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 ownership interest (%)
Book value of the investment
Revenues and other operating income
Operating expense
Depreciation, amortization and impairments
Operating profit
Finance (expense) income
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
1,366
883
11,407
12,773
608
7,139
366
7,747
5,026
69.60
3,498
Saipem
SpA
6,211
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)
Unión
Fenosa
Gas SA
664
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)
2018
Gas Distribution
Company of
Thessaloniki-
Thessaly SA
32
13
302
334
52
Cardón IV
SA
191
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)
2
54
280
49.00
137
53
(16)
(12)
25
25
(8)
17
17
8
8
Lotte Versalis
Elastomers
Co Ltd
56
8
502
558
111
78
297
289
408
150
50.00
75
22
(58)
(30)
(66)
(12)
(78)
(78)
(78)
(39)
PetroJunín
SA
368
253
621
470
34
504
117
40.00
47
112
(100)
(394)
(382)
31
(351)
(19)
(370)
11
(359)
(148)
Other
joint
ventures
130
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 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 233
2017
(€ 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 ownership interest (%)
Book value of the investment
Revenues and other operating income
Operating expense
Depreciation, amortization and impairments
Operating profit
Finance (expense) income
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
Saipem SpA
6,743
1,751
5,847
12,590
4,487
189
3,504
2,929
7,991
4,599
31.00
1,413
Unión Fenosa
Gas SA
610
32
877
1,487
234
40
580
506
814
673
50.00
350
9,038
(8,172)
(740)
126
(223)
(9)
(106)
(201)
(307)
49
(258)
(101)
1,340
(1,308)
(89)
(57)
(38)
3
(92)
1
(91)
(41)
(132)
(63)
Petro
Junín SA
365
628
993
434
34
468
525
40.00
210
135
(66)
(29)
40
47
87
(22)
65
(68)
(3)
26
2017
Gas Distribution
Company of
Thessaloniki-Thessaly SA
86
15
289
375
94
2
96
279
49.00
137
54
(14)
(15)
25
25
(7)
18
18
9
12
Lotte
Versalis
Elastomers
Co Ltd
43
30
547
590
70
38
292
288
362
228
50.00
114
(4)
(4)
(4)
(4)
(6)
(10)
(2)
Cardón IV SA
816
42
2,756
3,572
644
2,928
1,912
3,572
50.00
756
(608)
(357)
(209)
(155)
(364)
(4)
(368)
26
(394)
(184)
Other joint
ventures
275
64
916
1,191
985
640
124
79
1,109
82
28
412
(433)
(113)
(134)
(53)
(4)
(191)
(11)
(202)
(202)
(56)
29
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018
234
The 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:
2018
(€ 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 ownership interest (%)
Book value of the investment
Revenues and other operating income
Operating expense
Depreciation, amortization and impairments
Operating profit
Finance (expense) income
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
l
o
g
n
A
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
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS
2017
(€ 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 ownership interest (%)
Book value of the investment
Revenues and other operating income
Operating expense
Depreciation, amortization and impairments
Operating profit
Finance (expense) income
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
235
2017
A
S
G
N
L
F
l
a
r
o
C
36
19
1,261
1,297
155
926
926
1,081
216
25.00
54
4
4
4
(13)
(9)
1
d
t
L
G
N
L
a
o
g
n
A
l
662
370
7,048
7,710
203
1,610
1,418
1,813
5,897
13.60
802
1,374
(563)
(399)
412
(80)
332
332
(817)
(485)
45
s
e
t
a
i
c
o
s
s
a
r
e
h
t
O
338
89
528
866
220
42
124
71
344
522
205
574
(454)
(40)
80
3
(30)
53
(19)
34
(39)
(5)
8
13
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 the assistance
received from Italian public authorities and entities, as well as
the assistance granted by Eni SpA and by its fully consolidated
subsidiaries to companies, persons and public and private entities, are
provided below. The consolidated disclosures include: (i) assistance
received from Italian public authorities/entities; and (ii) assistance
granted by Eni SpA and its subsidiaries32.
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, including 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. The assistance to be disclosed
is identified on a cash basis.
The disclosure includes assistance exceeding €10,000, even though
they are granted through several payments.
Under art. 3-quarter of the Italian Decree Law No. 135/2018, converted
with amendments by Law 11 February 2019, n. 12, for the received
assistance see the information included in the Italian State aid
Register, prepared in accordance with the article 52 of the Italian Law
24 December 2012, No. 234.
(32) The following disclosures do not include assistance granted by foreign subsidiaries to foreign beneficiaries.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTSEni Annual Report 2018
236
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:
Amount paid
(€)
4,403,686
3,389,902
3,052,192
1,000,000
260,586
242,326
83,358
81,307
72,805
57,000
51,588
50,000
40,000
35,000
35,000
33,000
30,000
29,687
26,000
22,548
22,000
21,985
21,760
20,000
20,000
20,000
14,000
10,000
Assistance granted
Granted subject
Fondazione Eni Enrico Mattei
Eni Foundation
Fondazione Teatro alla Scala
Fondazione Giorgio Cini
WEF - World Economic Forum
Comitato Sisma Centro Italia - Confindustria, CIGL, CISL e UIL - Fondo di solidarietà per le popolazioni Centro Italia
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
Fondazione Camera Centro Italiano per la Fotografia
Istituto Giannina Gaslini
Center for Strategic & International Studies
Politecnico di Milano - Dipartimento di “Scienze e Tecnologie Energetiche e Nucleari”
Institute for Human Rights and Business (IHRB)
Associazione Civita
Foreign Policy Association - USA
The Metropolitan Museum of Arts
Associazione Amici della Luiss
Centro Studi Americani
Fondazione Human Foundation Giving and Innovating Onlus
Global Reporting Initiative
Lega Italiana Fibrosi Cistica Lazio Onlus
39 | Significant non-recurring events and operations
In 2018, in 2017 and 2016, Eni did not report any non-recurring events and operations.
40 | Positions or transactions deriving from atypical and/or unusual operations
In 2018, 2017 and 2016 no transactions deriving from atypical and/or unusual operations were reported.
41 | Subsequent events
No significant events were reported after December 31, 2018.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | NOTES ON CONSOLIDATED FINANCIAL STATEMENTS 237
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&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)
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 equi-
ty-accounted entities(a)(b)
2017
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)
Rest
Sub-Saharan
Italy
of Europe North Africa
Egypt
Africa Kazakhstan
Rest
of Asia
America
Australia
and Oceania
Total
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
16,277
18
359
681
17,335
17,600
356
39
345
18,340
12,514
471
1,436
2,050
16,471
15,211
32
191
1,297
16,731
36,976
2,157
1,212
2,679
43,024
10,547
3
101
1,417
12,068
12,493
1,023
34
421
13,971
14,840
785
46
280
15,951
1,950
185
14
124
2,273
138,408
5,030
3,432
9,294
156,164
(13,504)
(12,014)
(10,640)
(10,413)
(25,920)
(1,690)
(10,386)
(12,534)
(1,188)
(98,289)
3,831
6,326
5,831
6,318
17,104
10,378
3,585
3,417
1,085
57,875
4
1
5
5
67
7
6
80
(61)
19
1,419
4
1,423
(475)
948
581
85
93
759
1,833
6
225
2,064
(611)
(785)
148
1,279
3,900
89
13
329
4,331
(1,932)
2,399
(a) The amounts include net capitalized financial charges totalling €831 million in 2018 and €969 million in 2017 for the consolidated subsidiaries and €180 million in 2018 and €78
million in 2017 for equity-accounted entities.
(b) Includes Vår Energi AS asset fair value.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | SUPPLEMENTAL OIL AND GAS INFORMATIONEni Annual Report 2018
238
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:
Italy
Rest of
Europe North Africa
Sub-Saharan
Egypt
Africa Kazakhstan
Rest of
Asia
America
Australia
and Oceania
(€ million)
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
2016
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
26
382
408
106
557
663
43
445
488
102
2,216
2,318
66
1,379
1,445
3
92
95
2
3
5
77
785
862
110
3,041
3,151
2
2
58
694
752
1
1
2
306
1,752
2,060
5
65
1,939
2,009
9
9
70
2,019
2,089
28
28
31
251
282
27
387
414
242
364
606
1
1
51
437
488
1
1
Total
382
487
750
6,036
7,655
105
(13)
92
5
715
7,646
8,366
91
63
154
2
621
7,168
7,791
14
136
150
7
36
43
5
14
19
3
1
4
215
340
555
(16)
(16)
106
292
398
48
48
26
(5)
21
95
95
382
487
182
589
1,640
103
103
76
714
790
90
4
94
3
246
249
80
1,232
1,312
651
651
13
12
25
(a) Includes the abandonment costs of the assets negative for €517 million in 2018, assets for €355 million in 2017, negative for €665 million in 2016.
(b) Includes the abandonment costs of the assets negative for €22 million in 2018, negative €23 million in 2017, negative for €15 million in 2016.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | SUPPLEMENTAL OIL AND GAS INFORMATION 239
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:
Rest
Sub-Saharan
Italy
of Europe North Africa
Egypt
Africa Kazakhstan
Rest
of Asia
America
Australia
and Oceania
Total
2,120
2,120
(410)
(402)
(8)
(171)
(25)
(281)
(442)
791
(170)
2,740
494
3,234
(630)
(488)
(142)
(85)
(664)
(193)
1,277
3,741
5,018
(413)
(363)
(50)
(243)
(48)
(582)
(101)
1,662
(1,070)
3,631
(2,494)
3,207
3,207
(354)
(343)
(11)
(22)
(795)
(239)
1,797
(542)
4,701
830
5,531
(1,016)
(974)
(42)
(435)
(44)
(2,490)
(1,126)
420
(264)
1,140
769
1,909
(405)
(269)
(136)
(3)
(387)
(67)
1,047
(308)
1,902
493
2,395
(227)
(220)
(7)
(191)
(79)
(941)
(135)
822
(678)
621
592
1,137
1,255
156
739
144
(€ million)
2018
Consolidated subsidiaries
Revenues:
- sales to consolidated entities
- sales to third parties
Total revenues
Operations costs
- of which production costs
- of which 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
Operations costs
- of which production costs
- of which 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
15
15
(8)
(7)
(1)
(3)
(1)
2
5
(3)
2
(6)
(1)
(7)
(7)
257
257
(62)
(34)
(28)
(26)
224
(27)
366
366
(a) Includes asset net impairment amounting to €726 million.
934
50
984
(250)
(234)
(16)
(69)
(594)
(54)
17
7
24
420
420
(38)
(36)
(2)
(114)
(222)
(122)
(76)
(35)
6
6
(2)
(2)
(235)
(3)
(25)
(259)
(2)
(261)
(111)
4
190
194
(48)
(48)
(6)
(5)
(67)
14,818
9,774
24,592
(3,753)
(3,341)
(412)
(1,046)
(380)
(6,801)
(2,357)
68
(26)
10,255
(5,545)
42
4,710
698
698
(110)
(79)
(31)
(143)
(241)
(2)
(173)
29
(40)
(11)
CONSOLIDATED FINANCIAL STATEMENTS 2018 | SUPPLEMENTAL OIL AND GAS INFORMATIONEni Annual Report 2018 240
(€ million)
2017
Consolidated subsidiaries
Revenues:
- sales to consolidated entities
- sales to third parties
Total revenues
Operations costs
- of which production costs
- of which 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
Operations costs
- of which production costs
- of which 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
Egypt
Africa Kazakhstan
Sub-Saharan
Rest of
Asia
America
Australia
and Oceania
Total
1,619
1,619
(337)
(332)
(5)
(130)
(26)
(465)
1,563
2,224
(299)
1,897
481
2,378
(687)
(523)
(164)
(122)
(838)
(141)
590
(216)
1,056
3,184
4,240
(504)
(455)
(49)
(200)
(22)
(679)
(162)
2,673
(1,978)
2,128
2,128
(314)
(303)
(11)
(191)
(767)
690
1,546
(214)
3,888
547
4,435
(986)
(952)
(34)
(331)
(60)
(2,063)
(716)
279
(38)
681
713
1,394
(396)
(271)
(125)
(289)
(221)
488
(223)
911
291
1,202
(206)
(202)
(4)
(11)
(61)
(765)
(84)
75
(67)
932
96
1,028
(312)
(258)
(54)
(39)
(577)
(342)
(242)
(38)
3
168
171
(48)
(48)
(5)
(4)
(59)
2
57
(23)
10,987
7,608
18,595
(3,790)
(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
(8)
(6)
(2)
(2)
(1)
(2)
1
(1)
(1)
(2)
(3)
(3)
129
129
(37)
(19)
(18)
(8)
(54)
26
56
56
22
22
(9)
(9)
(13)
(13)
3
(10)
(4)
517
517
(40)
(39)
(1)
(146)
(271)
(199)
(139)
(20)
(14)
(159)
682
682
(94)
(73)
(21)
(156)
(14)
(339)
(174)
(95)
(25)
(120)
(a) Includes asset net reversal amounting to €158 million.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | SUPPLEMENTAL OIL AND GAS INFORMATION
241
(€ million)
2016
Consolidated subsidiaries
Revenues:
- sales to consolidated entities
- sales to third parties
Total revenues
Operations costs
- of which production costs
- of which 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
Operations costs
- of which production costs
- of which 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
Rest
Sub-Saharan
Italy
of Europe North Africa
Egypt
Africa Kazakhstan
Rest
of Asia
America
Australia
and Oceania
Total
1,217
1,217
(311)
(307)
(4)
(96)
(35)
(923)
(342)
(490)
159
1,673
432
2,105
(599)
(436)
(163)
(40)
(943)
(232)
291
(1)
932
2,841
3,773
(451)
(404)
(47)
(176)
(45)
(675)
(201)
2,225
(1,618)
9
1,471
1,480
(356)
(343)
(13)
(42)
(691)
(265)
126
(89)
(331)
290
607
37
15
15
(9)
(7)
(2)
(3)
(1)
(1)
1
(2)
(1)
(3)
(3)
(3)
3,178
485
3,663
(968)
(929)
(39)
(282)
(142)
(1,093)
(917)
261
97
358
(26)
(26)
(52)
(52)
252
606
858
(269)
(177)
(92)
(129)
(57)
403
(139)
1,027
114
1,141
(215)
(212)
(3)
(17)
(39)
(952)
(130)
(212)
32
833
102
935
(325)
(262)
(63)
(28)
(480)
(120)
(18)
(9)
4
165
169
(49)
(49)
(5)
(3)
(67)
(8)
37
(9)
9,125
6,216
15,341
(3,543)
(3,119)
(424)
(576)
(374)
(5,953)
(2,272)
2,623
(1,577)
264
(180)
(27)
28
1,046
36
36
(10)
(10)
(13)
(32)
(16)
(35)
(6)
493
493
(54)
(51)
(3)
(121)
(240)
(25)
53
(162)
(41)
(109)
544
544
(73)
(68)
(5)
(124)
(13)
(299)
(71)
(36)
(170)
(206)
(a) Includes asset net reversal amounting to €700 million.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | SUPPLEMENTAL OIL AND GAS INFORMATIONEni Annual Report 2018
242
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 2018, the average price for the marker Brent crude oil was $71
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 companies33. The description of
qualifications of the person primarily responsible of the reserves audit
is included in the third party audit report34.
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 2018, Ryder Scott Company, DeGolyer and MacNaughton and
Societé Generale de Surveillance (SGS)34 provided an independent
evaluation of about 26% of Eni’s total proved reserves as of December
31, 201835, confirming, as in previous years, the reasonableness of
Eni’s internal evaluations.
In the three years period from 2016 to 2018, 95% of Eni’s total proved
reserves were subject to independent evaluation. As of December 31,
2018, the principal property not subjected to independent evaluation
in the last three years was M’Boundi (Congo).
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 61%, 60% and 59% of total proved reserves as of December
31, 2018, 2017 and 2016, respectively, on an oil-equivalent basis.
Similar effects as PSAs apply to service contracts; proved reserves
associated with such contracts represented 3%, 4% and 5% of total
proved reserves on an oil-equivalent basis as of December 31, 2018,
2017 and 2016, 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%, 1.6% and 1.8% of total proved reserves as of
December 31, 2018, 2017 and 2016, 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, 2018, 2017 and 2016.
(33) From 1991 to 2002 DeGolyer and McNaughton, from 2003 also Ryder Scott. In 2018, Societé Generale de Surveillance (SGS) also provided an independent certification.
(34) The reports of independent engineers are available on Eni website eni.com, section Publications/Annual Report 2018.
(35) Including reserves of equity-accounted entities.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | SUPPLEMENTAL OIL AND GAS INFORMATION 243
CRUDE OIL (INCLUDING CONDENSATE AND NATURAL GAS LIQUIDS)
(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
Rest
of Europe
Italy
North Africa
Egypt
Africa Kazakhstan
Sub-Saharan
Rest
of Asia
America
Australia
and Oceania
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
Total
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 2018 | SUPPLEMENTAL OIL AND GAS INFORMATIONEni Annual Report 2018
24 4
(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
Rest
Sub-Saharan
Italy
of Europe North Africa
Egypt
Africa Kazakhstan
Rest
of Asia
America
Australia
and Oceania
Total
176
132
44
59
(20)
215
264
228
36
29
1
103
(37)
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 2018 | SUPPLEMENTAL OIL AND GAS INFORMATION 245
(million barrels)
2016
Consolidated subsidiaries
Reserves at December 31, 2015
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, 2016
Equity-accounted entities
Reserves at December 31, 2015
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, 2016
Reserves at December 31, 2016
Developed
consolidated subsidiaries
equity-accounted entities
Undeveloped
consolidated subsidiaries
equity-accounted entities
Rest
of Europe
Italy
North Africa
Egypt
Africa Kazakhstan
Sub-Saharan
Rest
of Asia
America
Australia and
Oceania
Total
228
171
57
(35)
(17)
176
305
237
68
(4)
1
2
(40)
264
494
312
182
19
1
1
(61)
327
230
97
(26)
8
(28)
454
281
13
13
1
(1)
13
467
300
287
13
167
167
281
205
205
76
76
176
132
132
44
44
264
228
228
36
36
787
511
276
113
(91)
809
16
6
10
(1)
15
824
515
507
8
309
302
7
771
355
416
262
126
136
189
149
40
20
73
(1)
9
9
1
(24)
(28)
(25)
(1)
3,372
2,100
1,272
160
2
11
(315)
767
307
767
556
556
211
211
307
124
124
183
183
163
158
29
129
(13)
(5)
140
303
165
143
22
138
20
118
9
3,230
187
48
139
(13)
(6)
168
3,398
2,233
2,190
43
1,165
1,040
125
9
8
8
1
1
CONSOLIDATED FINANCIAL STATEMENTS 2018 | SUPPLEMENTAL OIL AND GAS INFORMATIONEni Annual Report 2018
246
NATURAL GAS(a)
(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
Egypt
Africa Kazakhstan
Sub-Saharan
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
(19)
1,217
822
822
395
395
1,989
1,846
1,846
143
143
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)
(19)
2,400
19,724
13,266
11,203
2,063
6,458
6,121
337
(a) Values lower than 1 BCF are not disclosed in this table.
CONSOLIDATED FINANCIAL STATEMENTS 2018 | SUPPLEMENTAL OIL AND GAS INFORMATION
247
Rest
of Europe
Italy
North Africa
Egypt
Africa Kazakhstan
Sub-Saharan
Rest
of Asia
America
Australia
and Oceania
Total
(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
1,131
987
987
144
144
896
771
771
125
125
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
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
(1,565)
(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
741
559
182
6
(38)
709
709
519
519
190
190
18,462
9,244
9,218
1
1,499
(19)
1,936
(1,783)
(2,806)
17,290
3,871
1,905
1,966
(1,552)
(137)
2,182
19,472
11,451
9,535
1,916
8,021
7,755
266
CONSOLIDATED FINANCIAL STATEMENTS 2018 | SUPPLEMENTAL OIL AND GAS INFORMATIONEni Annual Report 2018
248
(billion cubic feet)
2016
Consolidated subsidiaries
Reserves at December 31, 2015
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, 2016
Equity-accounted entities
Reserves at December 31, 2015
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, 2016
Reserves at December 31, 2016
Developed
consolidated subsidiaries
equity-accounted entities
Undeveloped
consolidated subsidiaries
equity-accounted entities
Rest
of Europe
Italy
North Africa
Egypt
Africa Kazakhstan
of Asia America
Sub-Saharan
Rest
Australia
and Oceania
Total
1,304
1,051
253
1,044
919
125
3,851
1,744
2,107
947
822
125
2,714
1,390
1,324
2,354
1,830
524
878
185
693
439
373
66
771
585
186
14,302
8,899
5,403
(155)
18
471
25
223
224
200
8
12
1,026
(172)
(184)
(584)
4,767
(219)
(170)
(93)
15
(90)
(94)
(42)
4,782
(1,648)
977
878
3,738
5,520
2,767
2,485
1,003
353
741
18,462
13
13
4
(2)
977
845
845
132
132
878
801
801
77
77
15
3,753
1,747
1,732
15
2,006
2,006
5,520
799
799
4,721
4,721
387
85
302
(8)
(11)
368
3,135
1,755
1,651
104
1,380
1,116
264
12
9
3
3,581
1,295
2,286
(1)
(4)
(7)
(93)
4
1,007
284
280
4
723
723
2,485
2,239
2,239
246
246
3,484
3,837
2,120
338
1,782
1,717
15
1,702
741
559
559
182
182
3,993
1,402
2,591
(9)
(113)
3,871
22,333
11,149
9,244
1,905
11,184
9,218
1,966
CONSOLIDATED FINANCIAL STATEMENTS 2018 | SUPPLEMENTAL OIL AND GAS INFORMATION
249
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.
The standardized measure of discounted future net cash flows by
geographical area consists of the following:
(€ 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
Rest
Sub-Saharan
Italy
of Europe North Africa
Egypt
Africa Kazakhstan
Rest
of Asia
America
Australia
and Oceania
Total
18,372
(5,659)
4,895
(1,438)
43,578
39,193
(6,653) (12,193)
53,534
(16,417)
40,698
(8,276)
33,384
(9,492)
14,192
(6,038)
2,319
(511)
250,165
(66,677)
(4,670)
(1,350)
(4,700)
(2,769)
(6,778)
(2,640)
(5,755)
(2,467)
(291)
(31,420)
8,043
(1,671)
6,372
(2,045)
2,107
(798)
1,309
(124)
32,225
(17,514)
14,711
(6,727)
24,231
(7,829)
16,402
(6,564)
30,339
(11,566)
18,773
(7,501)
29,782
(6,524)
23,258
(12,477)
18,137
(11,980)
6,157
(2,258)
5,687
(1,791)
3,896
(1,508)
1,517
(289)
1,228
(491)
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)
2,363
347
(138)
(3)
206
(43)
163
(76)
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
CONSOLIDATED FINANCIAL STATEMENTS 2018 | SUPPLEMENTAL OIL AND GAS INFORMATIONEni Annual Report 2018
250
(€ 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
(€ million)
December 31, 2016
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
Sub-Saharan
Italy
of Europe North Africa
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)
41,136
(14,790)
30,263
(6,992)
11,826
(3,653)
6,205
(2,351)
2,593 186,818
(52,008)
(590)
(3,943)
(5,483)
(4,350)
(4,496)
(6,522)
(2,787)
(3,694)
(1,011)
(318) (32,604)
5,305
(859)
4,446
(1,633)
8,313
(4,490)
3,823
(1,050)
20,766
(10,836)
9,930
(4,566)
18,507
(5,709)
12,798
(6,698)
19,824
(6,418)
13,406
(5,430)
20,484
(3,970)
16,514
(9,172)
4,479
(757)
3,722
(1,239)
2,843
(699)
2,144
(777)
1,685 102,206
(34,041)
(303)
68,165
1,382
(31,172)
(607)
2,813
2,773
5,364
6,100
245
(119)
(1)
125
(21)
104
(50)
54
7,976
2,062
(930)
(66)
1,066
(57)
1,009
(471)
538
7,342
2,483
1,367
775
36,993
11
(6)
10,797
(3,291)
(535)
6,971
(2,459)
4,512
(2,475)
5
(1)
4
4
2,037
13,115
(4,346)
(602)
8,167
(2,538)
5,629
(2,996)
2,633
2,813
2,773
5,418
6,100
8,514
7,342
2,487
3,404
775
39,626
Rest
Sub-Saharan
Italy
of Europe North Africa
Egypt
Africa Kazakhstan
Rest
of Asia
America
Australia and
Oceania
Total
9,627
(4,136)
12,898
(5,240)
30,847
(7,481)
33,524
(7,927)
38,271
(13,913)
26,903
(9,247)
12,263
(3,498)
5,789
(2,935)
2,815
(658)
172,937
(55,035)
(3,641)
(3,575)
(5,904)
(6,981)
(9,392)
(3,268)
(5,047)
(1,313)
(270)
(39,391)
1,850
(237)
1,613
(241)
4,083
(1,308)
2,775
(365)
17,462
(9,253)
8,209
(4,060)
18,616
(5,941)
12,675
(8,055)
14,966
(4,525)
10,441
(4,594)
14,388
(2,596)
11,792
(6,536)
3,718
(953)
2,765
(1,266)
1,541
(298)
1,243
(501)
1,887
(341)
1,546
(724)
78,511
(25,452)
53,059
(26,342)
1,372
2,410
4,149
4,620
259
(143)
(1)
115
(21)
94
(46)
48
5,847
2,429
(974)
(64)
1,391
(115)
1,276
(734)
542
5,256
1,499
742
822
26,717
33
(20)
16,430
(4,614)
(1,186)
10,630
(3,667)
6,963
(4,441)
13
(4)
9
9
2,522
19,151
(5,751)
(1,251)
12,149
(3,807)
8,342
(5,221)
3,121
1,372
2,410
4,197
4,620
6,389
5,256
1,508
3,264
822
29,838
CONSOLIDATED FINANCIAL STATEMENTS 2018 | SUPPLEMENTAL OIL AND GAS INFORMATION
251
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, 2018, 2017 and 2016, are as follows:
Consolidated
subsidiaries
Equity-accounted
entities
(€ million)
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
2016
Standardized measure of discounted future net cash flows at December 31, 2015
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, 2016
36,993
(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
26,717
(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
34,469
(11,222)
(24,727)
4,563
(2,357)
7,578
2,840
5,705
9,200
668
(7,752)
26,717
Total
39,626
(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
2,633
(445)
671
216
14
(803)
384
193
6,700
(4,322)
2,608
5,241
3,121
29,838
(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
3,321
37,790
(347)
(1,586)
650
151
(131)
514
386
163
(200)
3,121
(11,569)
(26,313)
4,563
(1,707)
7,729
2,709
6,219
9,586
831
(7,952)
29,838
CONSOLIDATED FINANCIAL STATEMENTS 2018 | SUPPLEMENTAL OIL AND GAS INFORMATIONEni Annual Report 2018
252
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, 2018 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 2018 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 2018 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.
March 14, 2019
/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
253
254
255
256
257
258
Annex
2018
2 |
M A N A G E M E N T R E P O R T
1 3 7 |
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 5 9 |
A N N E X
List of companies owned by Eni SpA as of December 31, 2018
Investments owned by Eni as of December 31, 2018
Changes in the scope of consolidation for 2018
260
260
282
260
LIST OF COMPANIES OWNED BY ENI SPA
AS OF DECEMBER 31, 2018
INVESTMENTS OWNED BY ENI
AS OF DECEMBER 31, 2018
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,
associates and significant investments owned by Eni SpA as of
December 31, 2018, 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
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, 2018,
the breakdown of the companies owned by Eni is provided in the
table below:
Fully consolidated subsidiaries
Consolidated joint operations
Investments owned by consolidated
companies(b)
Equity-accounted investments
Investments valued at cost
Investments valued at fair value
Investments owned by unconsolidated
companies
Owned by joint arrangements
Subsidiaries
Italy
Outside
Italy
28
147
Total
175
Joint arrangements
and associates
Other significant investments(a)
Italy
Outside
Italy
Total
Italy
Outside
Italy
Total
7
5
12
4
4
8
26
4
30
30
8
38
18
3
21
36
31
67
3
3
75
54
34
88
3
3
103
3
3
3
22
22
25
25
22
25
Total
36
177
213
28
(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 valued at cost relate to non-significant companies.
SUBSIDIARIES AND JOINT ARRANGEMENTS
RESIDENT IN STATES OR TERRITORY WITH
A PRIVILEGED TAX REGIME
The Law of December 28, 2015, No. 208 (Stability Law 2016),
effective from January 1, 2016, amended the article No. 167,
paragraph 4, of the Presidential Decree of December 22, 1986
No. 917, identifying all the tax regimes, even special, of states
or territories to be considered as privileged with reference,
exclusively, to a nominal level of taxation lower than 50 percent
of the one applicable in Italy. Furthermore, the regimes of
states or territories that are part of the European Union, or of
states that are part of the European Economic Area that have
concluded agreements with Italy ensuring an effective exchange
of information are not considered as privileged. At December 31,
2018, Eni controls 10 companies based in states with a privileged
tax regime as identified by article No. 167, paragraph 4 of the
Italian Income Tax Code. Of these 10 companies, 6 are subject to
taxation in Italy because they are included in the tax return of Eni.
The remaining 4 companies are not subject to Italian taxation,
but to the specific local tax regimes, as a consequence of the
exemption obtained by the Italian Revenue Agency by taking into
account of the taxation level applied. Of these 10 companies, 8
come from the acquisitions of Lasmo Plc, the activities carried out
in Congo by Maurel & Prom, Burren Energy Plc and Hess Indonesia.
These subsidiaries, resident or located in states identified by the
Decree, did not issued any financial instrument and all the financial
statements for 2018 will be audited by Ernst & Young.
ANNEX TO FINANCIAL STATEMENTS | INVESTMMENTS OWNED BY ENI AS OF DECEMBER 31, 2018
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
261
p
i
h
s
r
e
n
w
O
%
25.76
4.34
0.91
68.99
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
Eni Zubair SpA
(in liquidation)
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)
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
%
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
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
Italy
EUR
120,000
Eni SpA
100.00
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.
Co.
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 | SUBSIDIARIESEni Annual Report 2018
262
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 Oil Ecuador BV
Agip Oleoducto de Crudos
Pesados BV
Burren Energy (Bermuda) Ltd(9)
Burren Energy (Egypt) Ltd
Burren Energy Congo Ltd(9)
Burren Energy India Ltd
Burren Energy Plc
Burren Shakti Ltd(8)
Eni Abu Dhabi BV
Eni AEP Ltd
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)
Amsterdam
(Netherlands)
Hamilton
(Bermuda)
London
(United Kingdom)
Tortola
(British Virgin
Islands)
London
(United Kingdom)
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
Ecuador
United
Kingdom
Egypt
Republic of the
Congo
United
Kingdom
EUR
EUR
USD
GBP
USD
GBP
20,000
Eni International BV
100.00
100.00
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
2
Burren Energy Plc
100.00
100.00
London
(United Kingdom)
United
Kingdom
Hamilton
(Bermuda)
United
Kingdom
Amsterdam
(Netherlands)
United Arab
Emirates
GBP
28,819,023
Eni UK Holding Plc
Eni UK Ltd
99.99
(..)
100.00
USD
65,300,000
Burren En. India Ltd
100.00
100.00
EUR
20,000
Eni International BV
100.00
100.00
London
(United Kingdom)
Amsterdam
(Netherlands)
Luxembourg
(Luxembourg)
Amsterdam
(Netherlands)
London
(United Kingdom)
Pakistan
GBP
73,471,000
Eni UK Ltd
100.00
100.00
Algeria
Algeria
Algeria
EUR
USD
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
Indonesia
GBP
1
Eni Indonesia Ltd
100.00
100.00
USD
EUR
EUR
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
Dover, Delaware
(USA)
USA
Angola
Angola
Amsterdam
(Netherlands)
Amsterdam
(Netherlands)
Buenos Aires
(Argentina)
Argentina
ARS
24,136,336
Eni International BV
Eni Oil Holdings BV
95.00
5.00
London
(United Kingdom)
Indonesia
Amsterdam
(Netherlands)
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)
Australia
GBP
20,000,000
Eni International BV
100.00
100.00
Netherlands
EUR
20,000
Eni International BV
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
F.C.
F.C.
F.C.
F.C.
Eq.
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.
Eq.
F.C.
F.C.
F.C.
Eq.
(*) F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.
(8) Company located in a state or territory with a privileged tax regime as provided in article 167 paragraph 4 of Presidential Decree of December 22, 1986, No. 917: the profit pertaining to the Group is
subject to the Italian taxation.
(9) Company located in a state or territory with a privileged tax regime as provided in article 167 paragraph 4 of Presidential Decree of December 22, 1986, No. 917: the company is not subject to the Italian
taxation following the admission of the instance by the Italian Revenue Agency.
ANNEX TO FINANCIAL STATEMENTS | SUBSIDIARIES
e
m
a
n
y
n
a
p
m
o
C
Eni BB Petroleum Inc
Eni BTC Ltd
Eni Bukat Ltd
Eni Bulungan BV
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
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
Dover, Delaware
(USA)
USA
London
(United Kingdom)
United
Kingdom
London
(United Kingdom)
Indonesia
Indonesia
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
GBP
23,214,400
Eni International BV
100.00
GBP
EUR
1
Eni Indonesia Ltd
100.00
100.00
20,000
Eni International BV
100.00
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)
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 UK Ltd
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
100,00
Brazil
BRL
1,593,415,000
Eni International BV
Eni Oil Holdings BV
99.99
(..)
Indonesia
GBP
Indonesia
GBP
1
1
Eni Indonesia Ltd
100.00
100.00
Eni Indonesia Ltd
100.00
100.00
London
(United Kingdom)
United
Kingdom
GBP
100
Eni UK Ltd
100.00
100.00
Amsterdam
(Netherlands)
Amsterdam
(Netherlands)
Libreville
(Gabon)
London
(United Kingdom)
Amsterdam
(Netherlands)
Accra
(Ghana)
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
Aberdeen
(United Kingdom)
United
Kingdom
GBP
3,036,000
Eni UK Ltd
100.00
100.00
London
(United Kingdom)
London
(United Kingdom)
London
(United Kingdom)
Venezuela
GBP
8,050,500
Eni Lasmo Plc
100.00
100.00
India
GBP
44,000,000
Eni UK Ltd
100.00
100.00
Indonesia
GBP
100
Eni ULX 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.
263
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
F.C.
Eq.
F.C.
Eq.
F.C.
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.
ANNEX TO FINANCIAL STATEMENTS | SUBSIDIARIESEni Annual Report 2018
264
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
%
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
Eni Indonesia Ots 1 Ltd(8)
Eni International NA NV Sàrl
Eni Investments Plc
Grand Cayman
(Cayman Islands)
Indonesia
USD
1.01
Eni Indonesia Ltd
100.00
100.00
Luxembourg
(Luxembourg)
United
Kingdom
London
(United Kingdom)
United
Kingdom
USD
25,000
Eni International BV
100.00
100.00
GBP
750,050,000
Eni SpA
Eni UK Ltd
99.99
(..)
100.00
Eni Iran BV
Eni Iraq BV(24)
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
Amsterdam
(Netherlands)
Amsterdam
(Netherlands)
Amsterdam
(Netherlands)
Amsterdam
(Netherlands)
London
(United Kingdom)
Perth
(Australia)
Amsterdam
(Netherlands)
Amsterdam
(Netherlands)
London
(United Kingdom)
Iran
Iraq
Ireland
EUR
EUR
EUR
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
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
EUR
EUR
50,000
Eni International BV
100.00
100.00
20,000
Eni International BV
100.00
100.00
Indonesia
GBP
2
Eni Indonesia Ltd
100.00
100.00
London
(United Kingdom)
United
Kingdom
GBP 337,638,724.25
Eni Investments Plc
Eni UK Ltd
99.99
(..)
100.00
Amsterdam
(Netherlands)
Amsterdam
(Netherlands)
Lebanon
Liberia
London
(United Kingdom)
United
Kingdom
London
(United Kingdom)
United
Kingdom
Dover, Delaware
(USA)
USA
Amsterdam
(Netherlands)
Lomas De
Chapultepec,
Mexico City
(Mexico)
London
(United Kingdom)
Morocco
Mexico
United
Kingdom
EUR
EUR
GBP
20,000
Eni International BV
100.00
100.00
20,000
Eni International BV
100.00
100.00
1
Eni UK Ltd
100.00
GBP
80,400,000
Eni UK Ltd
100.00
100.00
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
GBP
1
Eni ULT Ltd
100.00
100.00
London
(United Kingdom)
United
Kingdom
GBP 220,711,147.50
Eni Lasmo Plc
Eni LNS Ltd
99.99
(..)
100.00
Amsterdam
(Netherlands)
London
(United Kingdom)
Amsterdam
(Netherlands)
Montenegro
EUR
20,000
Eni International BV
100.00
100.00
United
Kingdom
Netherlands
GBP
EUR
1
Eni UK Ltd
100.00
100.00
20,000
Eni International BV
100.00
100.00
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.
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. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value.
(8) Company located in a state or territory with a privileged tax regime as provided in article 167 paragraph 4 of Presidential Decree of December 22, 1986, No. 917: the profit pertaining to the Group is
subject to the Italian taxation.
(24) The company has a branch in Iraq and in Dubai, United Arab Emirates, state or territory with a privileged tax regime as provided in article 167, paragraph 4 of Presidential Decree of December 22, 1986,
No.917: the profit pertaining to the Group is subject to the Italian taxation.
ANNEX TO FINANCIAL STATEMENTS | SUBSIDIARIES
e
m
a
n
y
n
a
p
m
o
C
Eni Muara Bakau BV
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 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(9)
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
Amsterdam
(Netherlands)
Amsterdam
(Netherlands)
Amsterdam
(Netherlands)
London
(United Kingdom)
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
EUR
20,000
Eni International BV
100.00
100.00
Myanmar
Libya
EUR
EUR
20,000
Eni International BV
100.00
100.00
20,000
Eni International BV
100.00
100.00
Indonesia
GBP
1
Eni Indonesia Ltd
100.00
100.00
Dover, Delaware
(USA)
USA
London
(United Kingdom)
Algeria
USD
GBP
100,800
Eni America Ltd
100.00
100.00
1,000
Eni Lasmo Plc
100.00
100.00
Amsterdam
(Netherlands)
Amsterdam
(Netherlands)
London
(United Kingdom)
Luxembourg
(Luxembourg)
Dover, Delaware
(USA)
Dover, Delaware
(USA)
Amsterdam
(Netherlands)
London
(United Kingdom)
Kinshasa
(Democratic
Republic
of the Congo )
Amsterdam
(Netherlands)
Amsterdam
(Netherlands)
Amsterdam
(Netherlands)
Luxembourg
(Luxembourg)
Aberdeen
(Regno Unito)
Amsterdam
(Netherlands)
Hamilton
(Bermuda)
Netherlands
EUR
450,000
Eni ULX Ltd
100.00
100.00
Oman
EUR
20,000
Eni International BV
100.00
100.00
Pakistan
GBP
90,087
Eni ULX Ltd
100.00
100.00
Pakistan
USD
20,000
Eni Oil Holdings BV
100.00
100.00
USA
USA
Portugal
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
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
Netherlands
EUR
20,000
Eni International BV
100.00
100.00
Republic of
South Africa
China
United
Kingdom
Tunisia
EUR
USD
GBP
EUR
20,000
Eni International BV
100.00
100.00
20,000
Eni International BV
100.00
1,000
Eni UK Ltd
100.00
100.00
20,000
Eni International BV
100.00
100.00
Turkmenistan
USD
20,000
Burren En.(Berm)Ltd
100.00
100.00
London
(United Kingdom)
London
(United Kingdom)
United
Kingdom
United
Kingdom
London
(United Kingdom)
United
Kingdom
London
(United Kingdom)
United
Kingdom
GBP
1
Eni ULT Ltd
100.00
100.00
GBP
424,050,000
Eni Lasmo Plc
Eni UK Ltd
99.99
(..)
100.00
GBP
250,000,000
Eni International BV
100.00
100.00
GBP
100
Eni UK Ltd
100.00
100.00
265
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
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.
F.C.
Eq.
F.C.
F.C.
F.C.
Eq.
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.
(9) Company located in a state or territory with a privileged tax regime as provided in article 167 paragraph 4 of Presidential Decree of December 22, 1986, No. 917: the company is not subject to the Italian
taxation following the admission of the instance by the Italian Revenue Agency.
ANNEX TO FINANCIAL STATEMENTS | SUBSIDIARIESEni Annual Report 2018
266
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 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(9)
Liverpool Bay Ltd
Nigerian Agip CPFA Ltd
Nigerian Agip Exploration Ltd
Nigerian Agip Oil Co Ltd
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
Amsterdam
(Netherlands)
Kiev
(Ukraine)
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
%
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
100.00
99.99
0.01
100.00
London
(United Kingdom)
United
Kingdom
London
(United Kingdom)
United
Kingdom
GBP 93,215,492.25
Eni Lasmo Plc
100.00
100.00
GBP
200,010,000
Eni ULT Ltd
100.00
100.00
USA
USA
USA
USD
USD
USD
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
Venezuela
EUR
20,000
Eni Venezuela E&P H.
100.00
100.00
Belgium
USD
254,057,680
London
(United Kingdom)
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
(..)
Amsterdam
(Netherlands)
London
(United Kingdom)
Vietnam
EUR
20,000
Eni International BV
100.00
100.00
Indonesia
GBP
1
Eni Indonesia Ltd
100.00
100.00
1,000
Burren Energy Plc
100.00
London
(United Kingdom)
United
Kingdom
Egypt
GBP
EGP
Algeria
DZD
1,000,000
Eni Algeria Ltd Sàrl
50,000
EniProgetti SpA
Eni SpA
99.00
1.00
100.00
Algeria
Canada
Egypt
Egypt
USD
CAD
EUR
EUR
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
Indonesia
USD
12,000
Eni Lasmo Plc
100.00
100.00
London
(United Kingdom)
United
Kingdom
USD
1
Eni ULX Ltd
100.00
Lagos
(Nigeria)
Abuja
(Nigeria)
Abuja
(Nigeria)
Nigeria
NGN
1,262,500
Nigeria
NGN
5,000,000
Nigeria
NGN
1,800,000
NAOC Ltd
Agip En Nat Res. Ltd
Nigerian Agip E. Ltd
Eni International BV
Eni Oil Holdings BV
Eni International BV
Eni Oil Holdings BV
98.02
0.99
0.99
99.99
0.01
99.89
0.11
100.00
100.00
Dover, Delaware
(USA)
Dover, Delaware
(USA)
Dover, Delaware
(USA)
Amsterdam
(Netherlands)
Bruxelles
(Belgium)
Cairo
(Egypt)
Algiers
(Algeria)
Wilmington
(USA)
Calgary
(Canada)
Amsterdam
(Netherlands)
Amsterdam
(Netherlands)
Hamilton
(Bermuda)
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
F.C.
F.C.
Eq.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
F.C.
Co.
F.C.
F.C.
Eq.
Eq.
Eq.
F.C.
F.C.
F.C.
F.C.
F.C.
Eq.
Co.
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.
(9) Company located in a state or territory with a privileged tax regime as provided in article 167 paragraph 4 of Presidential Decree of December 22, 1986, No. 917: the company is not subject to the Italian
taxation following the admission of the instance by the Italian Revenue Agency.
ANNEX TO FINANCIAL STATEMENTS | SUBSIDIARIES
267
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m
a
n
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n
a
p
m
o
C
OOO “Eni Energhia”
Zetah Congo Ltd(8)
Zetah Kouilou Ltd(8)
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
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
Russia
RUB
2,000,000
Eni Energy Russia BV
Eni Oil Holdings BV
Republic of the
Congo
USD
300
Eni Congo SA
Burren En. Congo Ltd
Republic of the
Congo
USD
2,000
Eni Congo SA
Burren En. Congo Ltd
Third parties
o
i
t
a
r
y
t
i
u
q
E
%
100.00
p
i
h
s
r
e
n
w
O
%
99.90
0.10
66.67
33.33
54.50
37.00
8.50
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
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.
(8) Company located in a state or territory with a privileged tax regime as provided in article 167 paragraph 4 of Presidential Decree of December 22, 1986, No. 917: the profit pertaining to the Group is
subject to the Italian taxation.
ANNEX TO FINANCIAL STATEMENTS | SUBSIDIARIESEni Annual Report 2018
268
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
Trans Tunisian Pipeline Co SpA
San Donato
Milanese (MI)
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
Tunisia
EUR
1,098,000
Eni SpA
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.
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
F.C.
Co.
F.C.
F.C.
F.C.
F.C.
F.C.
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
F.C.
F.C.
F.C.
F.C.
Eq.
F.C.
F.C.
F.C.
ANNEX TO FINANCIAL STATEMENTS | SUBSIDIARIES
269
Refining & Marketing and Chemicals
Refining & Marketing
IN ITALY
e
m
a
n
y
n
a
p
m
o
C
Ecofuel SpA
Eni Fuel SpA
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
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 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)
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
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
%
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
EUR
52,000,000
Eni SpA
100.00
100.00
EUR
58,944,310
Eni SpA
100.00
100.00
EUR
15,000,000
Eni SpA
100.00
100.00
EUR
12,400,000
EUR 13,580,000.20
Ecofuel SpA
Third parties
Eni SpA
80.00
20.00
100.00
C.I.
C.I.
C.I.
P.N.
Co.
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
%
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
Netherlands
EUR
20,000
Eni International 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
EUR
17,299,100
Eni International BV
100.00
100.00
EUR
5,000,000
Eni International BV
100.00
100.00
Austria
EUR 19,621,665.23
Austria
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
100.00
Ecuador
Ecuador
USD
USD
60,000
30,000
Switzerland
CHF
7,000,000
Russia
RUB
1,010,000
Ecuador
USD
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
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.
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 | SUBSIDIARIESEni Annual Report 2018
270
Chemical
e
m
a
n
y
n
a
p
m
o
C
Versalis SpA
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
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
%
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
Italy
EUR 1,364,790,000
Eni SpA
100.00
100.00
F.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
%
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
Consorzio Industriale Gas Naturale
(in liquidation)
San Donato
Milanese (MI)
Italia
EUR
124,000
Versalis SpA
Raff. di Gela SpA
Eni SpA
Syndial SpA
Raff. Milazzo ScpA
53.55
18.74
15.37
0.76
11.58
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
p
i
h
s
r
e
n
w
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
Dunastyr Polisztirolgyártó Zártkörûen
Mûködõ Részvénytársaság
Budapest
(Hungary)
Hungary
HUF 8,092,160,000
USA
USD
100,000
Versalis SpA
Versalis Deutschland GmbH
Versalis International SA
Versalis International SA
96.34
1.83
1.83
100.00
100.00
100.00
Versalis Americas Inc
Versalis Congo Sarlu
Versalis Deutschland GmbH
Versalis France SAS
Versalis International SA
Versalis Kimya Ticaret Limited Sirketi
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)
Mumbai
(India)
Shanghai
(China)
Singapore
(Singapore)
London
(United Kingdom)
Republic of the
Congo
CDF
1,000,000
Versalis International SA
100.00
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
Turkey
India
China
TRY
INR
20,000
238,700
CNY
1,000,000
Versalis SpA
Versalis Deutschland GmbH
Dunastyr Zrt
Versalis France
Versalis International SA
Versalis Singapore P. Ltd
Third parties
Versalis SpA
59.00
23.71
14.43
2.86
100.00
99.99
(..)
100.00
100.00
100.00
Singapore
SGD
80,000
Versalis SpA
100.00
100.00
United
Kingdom
GBP
4,004,042
Versalis SpA
100.00
100.00
F.C.
F.C.
Eq.
F.C.
F.C.
F.C.
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 | SUBSIDIARIES
271
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
Eni Adfin SpA
(in liquidation)
Eni Corporate University SpA
EniServizi SpA
Serfactoring SpA
Servizi Aerei SpA
Rome
San Donato
Milanese (MI)
San Donato
Milanese (MI)
San Donato
Milanese (MI)
San Donato
Milanese (MI)
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
Italy
Italy
Italy
Italy
Italy
Italy
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
%
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
EUR
2,000,000
Eni SpA
100.00
100.00
EUR 85,537,498.80
Eni SpA
Third parties
EUR
3,360,000
Eni SpA
99.67
0.33
99.67
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
F.C.
F.C.
F.C.
F.C.
F.C.
F.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
%
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
Banque Eni SA
Eni Finance International SA
Eni Finance USA Inc
Eni Insurance Designated
Activity Company
Eni International BV
Bruxelles
(Belgium)
Bruxelles
(Belgium)
Belgium
EUR
50,000,000
Belgium
USD 2,474,225,632
Eni International BV
Eni Oil Holdings BV
Eni International BV
Eni SpA
99.90
0.10
66.39
33.61
100.00
100.00
Dover, Delaware
(USA)
USA
USD
15,000,000
Eni Petroleum Co Inc
100.00
100.00
Dublin
(Ireland)
Amsterdam
(Netherlands)
Ireland
EUR
500,000,000
Eni SpA
100.00
100.00
Netherlands
EUR
641,683,425
Eni SpA
100.00
100.00
Eni International Resources Ltd
Eni Next Llc
London
(United Kingdom)
United
Kingdom
Houston
(USA)
USA
GBP
USD
50,000
Eni SpA
Eni UK Ltd
99.99
(..)
100.00
100
Eni Petroleum Co Inc
100.00
100.00
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.
ANNEX TO FINANCIAL STATEMENTS | SUBSIDIARIESEni Annual Report 2018
272
Other Activities
IN ITALY
e
m
a
n
y
n
a
p
m
o
C
Anic Partecipazioni SpA
(in liquidation)
Eni Energia Srl
Eni New Energy SpA
Industria Siciliana Acido
Fosforico - ISAF - SpA
(in liquidation)
Ing. Luigi Conti Vecchi SpA
Syndial Servizi Ambientali SpA
OUTSIDE ITALY
e
m
a
n
y
n
a
p
m
o
C
Arm Wind Llp
Eni New Energy Egypt SAE
Oleodotto del Reno SA
Windirect BV
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
Gela (CL)
San Donato
Milanese (MI)
San Donato
Milanese (MI)
Gela
(CL)
Assemini
(CA)
San Donato
Milanese (MI)
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
Astana
(Kazakhstan)
Cairo
(Egypt)
Coira
(Switzerland)
Amsterdam
(Netherlands)
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
Italy
Italy
Italy
Italy
Italy
Italy
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
%
EUR
23,519,847.16
EUR
10,000
Syndial SpA
Third parties
Eni SpA
99.97
0.03
100.00
EUR
9,296,000
Eni SpA
100.00
100.00
EUR
1,300,000
Syndial SpA
Third parties
52.00
48.00
EUR
5,518,620.64
Syndial SpA
100.00
100.00
EUR
425,647,621.42
Eni SpA
Third parties
99.99
(..)
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
%
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.
F.C.
Eq.
F.C.
F.C.
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
Kazakhstan
KZT
2,133,967,100 Windirect BV
100.00
90.00
Egypt
EGP
250,000
Eni International BV
Ieoc Exploration BV
Ieoc Production BV
Switzerland
CHF
1,550,000
Syndial SpA
Netherlands
EUR
10,000
Eni International BV
Soci Terzi
99.98
0.01
0.01
100.00
90.00
10.00
90.00
F.C.
Eq.
Eq.
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 | SUBSIDIARIES
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
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
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
Company(†)
El-Fayrouz Petroleum Co(†)
(in liquidation)
El Temsah Petroleum Co
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)
Astana
(Kazakhstan)
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
Egypt
EGP
20,000
Angola
USD
10,082,000,000
Egypt
Russia
EGP
USD
20,000
20,000
Mozambique
MZN
2,500,000
Venezuela
Venezuela
VES
VES
172.1
0.001
Mozambico
MZN
100,000,000
United Arab
Emirates
AED
500,000
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
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
Ieoc Production BV
Third parties
Ieoc Production BV
Third parties
Ieoc SpA
Third parties
Ieoc Exploration BV
Third parties
Ieoc Production BV
Third parties
Eni Energy Russia BV
Third parties
Eni Isatay
Third parties
Agip Karachaganak BV
Third parties
Agip Karachaganak BV
Third parties
Eni Middle E. Ltd
Third parties
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.
273
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
50.00
50.00
25.00
75.00
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 2018
274
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
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 Holding AS
Point Resources FPSO AS
PR Jotun DA
Port Said Petroleum Co(†)
Raml Petroleum Co
Ras Qattara Petroleum Co
Rovuma Basin LNG Land Limitada(†)
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(†)
Tapco Petrol Boru Hatti Sanayi
ve Ticaret AS(†)
(in liquidation)
Tecninco Engineering
Contractors Llp(†)
Thekah Petroleum Co
(in liquidation)
United Gas Derivatives Co
VIC CBM Ltd(†)
Virginia Indonesia Co CBM Ltd(†)
(USA)
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)
Sandnes
(Norway)
Cairo
(Egypt)
Cairo
(Egypt)
Cairo
(Egypt)
Maputo
(Mozambique)
Cairo
(Egypt)
Pointe-Noire
(Republic of the
Congo)
Tunisi
(Tunisia)
Tunisi
(Tunisia)
Istanbul
(Turkey)
Aksai
(Kazakhstan)
Cairo
(Egypt)
Cairo
(Egypt)
London
(United Kingdom)
London
(United Kingdom)
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
USA
Egypt
Libya
Egypt
Norway
Egypt
Egypt
Egypt
Venezuela
Venezuela
Venezuela
Egypt
Norway
y
c
n
e
r
r
u
C
USD
EGP
EUR
EGP
GBP
EGP
EGP
EGP
VES
VES
VES
EGP
NOK
o
i
t
a
r
y
t
i
u
q
E
%
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(a)
Eni Oil & Gas Inc
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
60,000 Vår Energi AS
p
i
h
s
r
e
n
w
O
%
32.50
67.50
25.00
75.00
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
Norway
NOK
150,100,000 PR FPSO Holding AS
100.00
Norway
Egypt
Egypt
Egypt
NOK
EGP
EGP
EGP
Mozambique
MZN
Egypt
Republic
of the Congo
Tunisia
Tunisia
Turkey
EGP
XAF
TND
TND
TRY
0(a)
PR FPSO AS
PR FPSO Holding AS
20,000 Ieoc Production BV
Third parties
20,000 Ieoc Production BV
Third parties
20,000 Ieoc Production BV
Third parties
140,000 Mozambique Rovuma
Venture SpA
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
9,850,000 Eni International BV
Third parties
Kazakhstan
KZT
29,478,455 EniProgetti SpA
Third parties
Egypt
Egypt
EGP
20,000 Ieoc Exploration BV
Third parties
USD
153,000,000 Eni International BV
Indonesia
Indonesia
USD
USD
Third parties
1,315,912 Eni Lasmo Plc
Third parties
631,640 Eni Lasmo Plc
Third parties
95.00
5.00
50.00
50.00
22.50
77.50
37.50
62.50
33.33
66.67
25.00
75.00
20.00
80.00
50.00
50.00
50.00
50.00
50.00
50.00
49.00
51.00
25.00
75.00
33.33
66.67
50.00
50.00
50.00
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.
(a) Shares without nominal value.
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.
Eq.
Eq.
Co.
Co.
Eq.
Eq.
Eq.
Co.
Co.
Co.
Co.
Co.
Co.
Eq.
Eq.
Co.
Co.
Eq.
Co.
Eq.
Eq.
Eq.
ANNEX TO FINANCIAL STATEMENTS | JOINT ARRANGEMENTS AND ASSOCIATES
275
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
Vår Energi AS(†)
(ex Eni Norge AS)
West Ashrafi Petroleum Co(†)
(in liquidation)
Forus
(Norway)
Cairo
(Egypt)
Norway
NOK
399,425,000 Eni International BV
Third parties
Egypt
EGP
20,000 Ieoc Exploration BV
Third parties
o
i
t
a
r
y
t
i
u
q
E
%
p
i
h
s
r
e
n
w
O
%
69.60
30.40
50.00
50.00
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.
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)
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
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
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
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
o
i
t
a
r
y
t
i
u
q
E
%
51.00
o
i
t
a
r
y
t
i
u
q
E
%
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
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.
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.
Transmediterranean Pipeline Co Ltd(†)(19) 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.
(19) Company located in a state or territory with a privileged tax regime as provided in article 167 paragraph 4 of Presidential Decree of December 22, 1986, No. 917: the profit pertaining to the Group
is subject to the Italian taxation. The company is considered as a controlled subsidiary as provided by article 167, paragraph 3, of the Italian Tax Consolidated Text.
ANNEX TO FINANCIAL STATEMENTS | JOINT ARRANGEMENTS AND ASSOCIATESEni Annual Report 2018
276
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
Arezzo Gas SpA(†)
Arezzo
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
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
%
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
EUR
394,000
Eq.
Eq.
Co.
J.O.
Eq.
Eq.
J.O.
Eq.
J.O.
Co.
Eq.
J.O.
J.O.
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
Livorno LNG Terminal SpA
Livorno
Petroven Srl(†)
Genova
Porto Petroli di Genova SpA
Genova
Italy
Italy
Italy
EUR
EUR
200,000
156,000
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
Eni Fuel SpA
Third parties
Ecofuel SpA
Third parties
Eni Fuel SpA
Third parties
Eni Fuel SpA
Third parties
Eni Fuel SpA
Third parties
Costiero Gas L. SpA
Third parties
Ecofuel SpA
Third parties
Ecofuel SpA
Third parties
Eni SpA
Third parties
Eni SpA
Third parties
Ecofuel SpA
Third parties
Eni SpA
Third parties
50.00
50.00
44.78
55.22
25.00
75.00
65.00
35.00
25.00
75.00
50.00
50.00
68.00
32.00
40.50
59.50
50.00
50.00
25.00
75.00
35.00
65.00
70.00
30.00
65.00
68.00
50.00
70.00
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
277
o
i
t
a
r
y
t
i
u
q
E
%
20.00
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.
J.O.
Eq.
Co.
Eq.
Co.
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
AET - Raffineriebeteiligungsgesellschaft
mbH(†)
Bayernoil Raffineriegesellschaft
mbH(†)
Schwedt
(Germany)
Vohburg
(Germany)
City Carburoil SA(†)
Egyptian International
Gas Technology Co
ENEOS Italsing Pte Ltd
FSH Flughafen Schwechat
Hydranten-Gesellschaft OG
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)
Vienna
(Austria)
Tremblay en
France
(France)
Tunisi
(Tunisia)
Amsterdam
(Netherlands)
Meyrin
(Switzerland)
Jose Puerto
La Cruz
(Venezuela)
Salisburgo
(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
Austria
EUR
7,798,020.99
France
EUR
1
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 Deutsch. GmbH
Third parties
Eni Deutsch. GmbH
Third parties
Eni Suisse SA
Third parties
Eni International BV
Third parties
Eni International BV
Third parties
Eni Marketing A. GmbH
Eni Mineralölh. GmbH
Eni Austria GmbH
Third parties
Eni France Sàrl
Third parties
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
%
33.33
66.67
20.00
80.00
49.91
50.09
40.00
60.00
22.50
77.50
14.56
14.56
14.56
56.32
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
50.00
Third parties 50.00
ANNEX TO FINANCIAL STATEMENTS | JOINT ARRANGEMENTS AND ASSOCIATESEni Annual Report 2018
278
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
Brindisi Servizi Generali Scarl
Brindisi
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
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
%
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
EUR
1,549,060
49.00
20.20
8.90
21.90
19.74
11.58
10.70
57.98
50.00
50.00
80.00
20.00
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
o
i
t
a
r
y
t
i
u
q
E
%
Eq.
Eq.
Eq.
Eq.
Eq.
Eq.
Eq.
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.
Eq.
IFM Ferrara ScpA
Ferrara
Italy
EUR
5,270,466
Matrìca SpA(†)
Newco Tech SpA(†)
(in liquidation)
Novamont SpA
Priolo Servizi ScpA
Porto Torres
(SS)
Novara
Novara
Melilli
(SR)
Italy
Italy
Italy
Italy
EUR
37,500,000
EUR
179,000
Versalis SpA
Genomatica Inc
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
Syndial SpA
EniPower SpA
Third parties
Versalis SpA
Syndial SpA
S.E.F. Srl
Third parties
Versalis SpA
Third parties
Versalis SpA
Third parties
Versalis SpA
Syndial SpA
Third parties
Versalis SpA
EniPower SpA
Ecofuel SpA
Third parties
Versalis SpA
Syndial 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(†)
Yeosu
(South Korea)
Takoradi
(Ghana)
South Korea
KRW 301,800,000,000
Ghana
GHS
5,650,000
Versalis SpA
Third parties
Versalis International SA
Third parties
(*) 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
279
o
i
t
a
r
y
t
i
u
q
E
%
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
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
Co.
Eq.
Eq.
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
Wilmington
(USA)
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
USA
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
%
USD
148,291,710.38
Eni Next Llc
Third parties
35.72
66.28
Corporate e Altre attività
Other activities
IN ITALY
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
Ferrandina (MT)
Italy
EUR
4,644,000
Nuoro
San Donato
Milanese (MI)
Italy
Italy
EUR
516,000
EUR 2,191,384,693
Syndial SpA
Third parties
Syndial SpA
Third parties
Eni SpA
Saipem SpA
Third parties
p
i
h
s
r
e
n
w
O
%
(a)
59.56
40.44
30.00
70.00
30.54
1.46
68.00
(b)
e
m
a
n
y
n
a
p
m
o
C
Filatura Tessile Nazionale
Italiana - FILTENI SpA
(in liquidation)
Ottana Sviluppo ScpA
(in liquidation)
Saipem SpA(#)(†)
OUTSIDE ITALY
e
m
a
n
y
n
a
p
m
o
C
Grid Edge (Private) Ltd(†)
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
Saddar Town -
Karachi
(Pakistan)
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
%
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
Pakistan
PKR
1,200,000
Eni International
BV
Third parties
40.00
60.00
Eq.
(*) 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) Controlling interest: Syndial SpA
(b) Controlling interest: Eni SpA
48.00
Third parties 52.00
30.99
Third parties 69.01
ANNEX TO FINANCIAL STATEMENTS | JOINT ARRANGEMENTS AND ASSOCIATESEni Annual Report 2018
280
■ OTHER SIGNIFICANT INVESTMENTS
Exploration & Production
IN ITALY
e
m
a
n
y
n
a
p
m
o
C
Consorzio Universitario in Ingegneria
per la Qualità e l’Innovazione
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
Pisa
e
c
ffi
o
d
e
r
e
t
s
i
g
e
R
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
Caracas
(Venezuela)
Lagos
(Nigeria)
West Perth
(Australia)
West Trenton
(USA)
Port Harcourt
(Nigeria)
Amsterdam
(Netherlands)
Luanda
(Angola)
Caracas
(Venezuela)
Luanda
(Angola)
Cairo
(Egypt)
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
%
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
135,000
Eni SpA
Third parties
25.00
75.00
F.V.
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
Italy
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
Venezuela
Nigeria
y
c
n
e
r
r
u
C
EUR
y
c
n
e
r
r
u
C
VES
USD
Angola
Venezuela
Angola
Egitto
AOA
VES
AOA
EGP
Australia
AUD
530,060,381.89
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
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
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
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
(*) 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
281
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
%
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
Norsea Gas GmbH
Emden
(Germany)
Germany
EUR
1,533,875.64
Eni International BV
Third parties
13.04
86.96
F.V.
Refining & Marketing e Chimica
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
Consorzio Nazionale per la Gestione
Raccolta e Trattamento degli Oli Minerali Usati
Società Italiana Oleodotti di Gaeta SpA(14)
Rome
Rome
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
Saudi European Petrochemical Company
‘IBN ZAHR’
S.I.P.G. Société Immobilier Pétrolier
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
Hamburg
(Germany)
Cuenca
(Ecuador)
Fos-Sur-Mer
(France)
Nanterre
(France)
London
(United Kingdom)
Al Jubail
(Saudi Arabia)
Tremblay en France
(France)
Madrid
(Spain)
Hamburg
(Germany)
Ruemlang
(Switzerland)
Accra
(Ghana)
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
Italy
Italy
n
o
i
t
a
r
e
p
o
f
o
y
r
t
n
u
o
C
Germany
Ecuador
France
France
United
Kingdom
Saudi Arabia
France
Spain
Germany
y
c
n
e
r
r
u
C
EUR
ITL
y
c
n
e
r
r
u
C
EUR
USD
EUR
EUR
GBP
SAR
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
36,149
360,000,000
Eni SpA
Third parties
Eni SpA
Third parties
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
3,028,749
3,954,196.40
207,500
0(a)
1,200,000,000
40,000
175,713
4,953
Eni Deutsch. GmbH
Third parties
Eni Ecuador SA
Third parties
Eni France Sàrl
Third parties
Eni France Sàrl
Third parties
Eni SpA
Third parties
Ecofuel SpA
Third parties
Eni France Sàrl
Third parties
Eni Iberia SLU
Third parties
Eni Deutsch. GmbH
Third parties
Eni Suisse SA
Third parties
Eni International BV
Third parties
n
o
i
t
a
d
i
l
o
s
n
o
C
n
o
i
t
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n
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(
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F.V.
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
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w
O
%
12.43
87.57
72.48
27.52
p
i
h
s
r
e
n
w
O
%
12.50
87.50
13.31
86.69
16.81
83.19
18.00
82.00
12.50
87.50
10.00
90.00
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
(*) 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.
(14) 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 INVESTMENTSEni Annual Report 2018
282
■ CHANGES IN THE SCOPE OF CONSOLIDATION FOR 2018
Fully consolidated subsidiaries
COMPANIES INCLUDED (NO. 10)
Arm Wind Llp
Eni East Ganal Ltd
Eni Lebanon BV
Eni Next Llc
Eni Rovuma Basin BV
Eni Sharjah BV
Astana
London
Other activities
Acquisition
Exploration & Production
Constitution
Amsterdam
Exploration & Production
Relevancy
Houston
Corporate and financial
companies
Constitution
Amsterdam
Exploration & Production
Relevancy
Amsterdam
Exploration & Production
Constitution
Gas Supply Company Thessaloniki-Thessalia SA
Thessaloniki
Gas & Power
Acquisition of the control
Mestni Plinovodi distribucija plina doo
Koper
Gas & Power
Acquisition
Versalis Singapore Pte Ltd
Singapore
Chemical
Relevancy
Windirect BV
Amsterdam
Other activities
Acquisition
COMPANIES EXCLUDED (NO. 10)
Eni Bulungan BV
Eni Croatia BV
Amsterdam
Exploration & Production
Irrelevancy
Amsterdam
Exploration & Production
Sale
Sale
Eni Trinidad and Tobago Ltd
Port of Spain
Exploration & Production
Eni Engineering E&P Ltd
Eni Liverpool Bay Operating Co Ltd
Liverpool Bay Ltd
Mestni Plinovodi distribucija plina doo
Eni Norge AS
London
London
London
Koper
Forus
Exploration & Production
Cancellation
Exploration & Production
Irrelevancy
Exploration & Production
Irrelevancy
Gas & Power
Merger
Exploration & Production
Loss of control
Tigáz Tiszántúli Gázszolgáltató Zártkörûen Mûködõ Részvénytársaság
Hajdúszoboszló
Gas & Power
Tigáz-Dso Földgázelosztó kft
Hajdúszoboszló
Gas & Power
Sale
Sale
(*) 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.
(14) 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 | CHANGES IN THE SCOPE OF CONSOLIDATION FOR 2018 Eni SpA
Headquarters
Piazzale Enrico Mattei, 1 - Rome - Italy
Capital Stock as of December 31, 2018: € 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
Publications
Relazione Finanziaria Annuale pursuant to rule 154-ter paragraph 1 of Legislative Decree No. 58/1998 (in Italian)
Annual Report
Annual Report on Form 20-F for the Securities and Exchange Commission
Fact Book (in Italian and English)
Interim Consolidated Report as of June 30 pursuant to rule 154-ter paragraph 2 of Legislative Decree No. 58/1998 (in Italian and English)
Corporate Governance Report pursuant to rule 123-bis of Legislative Decree No. 58/1998 (in Italian and English)
Remuneration Report pursuant to rule 123-ter of Legislative Decree No. 58/1998 (in Italian and English)
ENI IN 2018 – Summary Annual Review (in English)
ENI FOR 2018 – Sustainability Report (in Italian and English)
Internet home page
www.eni.com
Rome office telephone
+39-0659821
Toll-free number
800940924
e-mail
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
Varigrafica Alto Lazio – Viterbo - Italy