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www.independentoilandgas.com
ANNUAL REPORT & ACCOUNTS 2018
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Independent Oil and Gas plc
Report and Audited Financial Statements
Year Ended
31 December 2018
Company Number 07434350
ANNUAL REPORT & ACCOUNTS 2018
Contents
Chief Executive’s Review ............................................................................................................. 2
Strategic Report ............................................................................................................................ 4
Page
Highlights of 2018 .............................................................................................................. 4
Post Year End Developments ........................................................................................... 5
Statement of Reserves & Resources ................................................................................ 9
Operational Update .......................................................................................................... 11
Finance Review ................................................................................................................ 20
Corporate Governance................................................................................................................ 23
Glossary of Key Terms ............................................................................................................... 35
Report of the Directors ............................................................................................................... 38
Statement of Directors’ Responsibilities ................................................................................... 40
Independent auditor’s report to the members of Independent Oil & Gas Plc ......................... 41
Consolidated Statement of Comprehensive Income ................................................................ 46
Consolidated and Company Statements of Changes in Equity ............................................... 47
Consolidated Statement of Financial Position .......................................................................... 48
Company Statement of Financial Position ................................................................................ 49
Consolidated Cash Flow Statement ........................................................................................... 50
Company Cash Flow Statement ................................................................................................. 51
Notes Forming Part of the Financial Statements ...................................................................... 52
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CHIEF EXECUTIVE’S REVIEW FOR THE YEAR ENDED 31 DECEMBER 2018
I am pleased to be able to report progress on all fronts in 2018 for Independent Oil and Gas plc (the ‘Company’) and
the Group (‘IOG’) across our UK Southern North Sea (‘SNS’) portfolio. We continue to move toward our goal of bringing
indigenous UK gas into the import-dependent UK market safely and at a low unit cost to generate material cash flows
for the Group and attractive returns for our shareholders.
During the year we have successfully added to our portfolio at low cost through successful awards made in the UK 30th
Offshore Licensing Round. On 23 May 2018 IOG was offered three new licences containing the Goddard discovery,
the south eastern Harvey structure and the Abbeydale discovery. Our core gas portfolio now comprises 302 BCF of
Proven and Probable (‘2P’) Reserves at the Blythe Hub (67 BCF)1 and the Vulcan Satellites Hub (235 BCF)1, 108 BCF
of Contingent 2C resources at Goddard with incremental upside of an additional 73BCF of Best Estimate Prospective
Resources at Goddard and a further 129 BCF Gross Best Estimate Prospective Resources at Harvey, our exciting
appraisal opportunity. The combined development of core and incremental upside is very valuable, targeting total daily
production of approximately 230mmcfd and an NPV10 of £688million as at year end 2018.
Throughout the year our development team has progressed the necessary engineering studies and benchmarked our
capital and operating costs versus the market, such that we have been able to quantify the cost base associated with
developing our portfolio and then to submit a revised Field Development Plan (‘FDP’) to the Oil and Gas Authority
(‘OGA’) in October 2018. This Field Development Plan envisages a phased approach to our core portfolio. Phase 1
comprises the Blythe Hub (the Blythe and Elgood Fields) and the Southwark Field from the Vulcan Satellites Hub. The
Nailsworth and Elland fields from the Vulcan Satellites form part of Phase 2 of the development. We plan to develop
Phase 1 via two simple unmanned wellhead platforms at Blythe and Southwark and a subsea tieback at Elgood, with
up to five long reach wells to be drilled. Initial analysis of the Goddard discovery acquired in the 30th UKCS Licensing
Round indicates that the 108 BCF of 2C Contingent Resources recognised within it may be included in the Core Project
development. Final Investment Decision (‘FID’) is planned within 1H 2019 and First Gas is targeted for the start of 2021,
from the Southwark field. In early 2018 an offshore survey campaign acquired all necessary environmental and survey
data for platform locations and connecting pipelines for Phase 1 and 2 core developments, excluding Goddard, and
external survey data for the Thames Pipeline. A second campaign in November 2018 acquired the necessary
geotechnical data for the Phase 1 development and for the Harvey appraisal well. At Harvey, PSDM reprocessing of
3D seismic data in the first half of 2018 and subsequent remapping in 3Q 2018 improved our understanding of the
incremental upside and we are seeking to appraise this structure at the earliest opportunity having committed to the
OGA to drill a well by the end of 2019. In the Harvey appraisal success case we would seek to incorporate this asset
into Phase 1 of the core development. On 11th February 2019 the Company allowed the Skipper Licence to expire in
order to focus our portfolio fully in the UK Southern North Sea Gas Basin.
The key to unlocking the value of our gas assets is the recommissioned Thames Pipeline (‘PL370’). This 24” gas line
was decommissioned in 2015 and bringing it back into operation will provide us with a low-cost export route via which
we can bring our gas to market at Bacton Terminal on the North Norfolk coast. In April 2018, we completed a Sales
and Purchase Agreement (‘SPA’) with PL370 owners Perenco UK Limited, Tullow Oil SK Limited and Centrica to
purchase the 90 km offshore line for a nominal sum and we have worked closely with the OGA, the Department of
Business, Energy & Industrial Strategy (‘BEIS’) and the Health & Safety Executive (‘HSE’) to become pipeline owner
and operator. As part of our offshore surveys campaign, the exterior of PL370 was surveyed and an extensive pigging
programme was executed to demonstrate its internal integrity in the first half of 2018. In view of equipment failure on
the intelligent pig run in May, a further crawler pig run was executed in September, demonstrating the viability of the
shoreward end of the line. A 150 bar 24 hour hydrotest in September demonstrated the capability of the line to
accommodate up to 550 mmcfd, providing us with ample capacity for our own portfolio, for any add-on opportunities we
deliver and for third-party business we may attract. Progress on the assessment and refurbishment of the Bacton
facilities, where the Thames Pipeline comes ashore, will commence in 1H 2020.
In support of our subsurface and engineering efforts the Company has been busy engaging with the supply chain who
we hope will be highly engaged partners in developing our gas hubs. To date, Letters of Intent have been signed with
Maersk (development drilling), Halliburton (well services), Offshore Design Engineering (‘ODE’) (duty holder, operations
and maintenance contractor), Heerema Fabrication Group (‘Heerema’ - offshore platform fabrication) and Allseas
(subsea and pipeline fabrication and installation contractors).
We are also pleased that in December 2018 the OGA granted an extension of the Blythe licence for a further year and
confirmed the waiver of the drill or drop commitment at Elgood allowing the Licence to pass into its second term. We
look forward to working ever closer with the OGA as we seek to bring our SNS gas assets into production.
1 Management Adjustment Estimates based on ERC Equipoise CPR, October 2017
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STRATEGIC REPORT FOR THE YEAR ENDED 31 DECEMBER 2018
Highlights of 2018
Operations
• Completion of the transformational acquisition of 100% operated ownership of the Thames Pipeline (‘PL370’) and
the demonstration of its viability to provide a stable export route for the Company’s 100% owned gas assets straight
to the UK market and National Transport System (‘NTS’).
o Offshore site and route survey along PL370, all proposed platform locations and intra-field connecting pipelines
completed in May 2018;
o Completion of the Intelligent Pigging Programme (‘IPP’) confirmed excellent condition of the PL370 infrastructure;
and
o Completion of tethered pig inspection together with 150-bar pressure hydrotest confirms PL370 economic life good
for the next two decades and condition ‘as new’ confirmed by analysis undertaken by Oilfield Testing Services.
• Significant operational progress towards delivering IOG’s SNS gas hub strategy.
o Environmental Impact Assessment (‘EIA’) submitted for the Blythe Hub in January 2018 and the Vulcan Satellites
Hub in April 2018;
o Platform fabrication Front End Engineering and Design (‘FEED’) undertaken by the Heerema Fabrication Group;
and
o FEED completed by Wood for the Subsea, Umbilicals, Risers and Flowlines (‘SURF’) scope of work on the Phase
1 development
• Strengthened portfolio around PL370 with the award of 100% ownership of three new licence areas, during the UKCS
30th Licensing Round - Goddard, Harvey SE and Abbeydale. Goddard adds 108 BCF of independently assessed 2C
Contingent Resources of gas and 73 BCF Best Case Prospective Gas Resources at Goddard.
• 3D seismic reprocessing over the Harvey structure completed and re-interpreted leading to revised management
estimate of Best-Case Prospective Resources of 129 BCF.
o Harvey appraisal well planned to spud in 2019, with the potential to significantly increase the Company’s resource
base.
Board and Management
• Refreshed Board and management team to drive future growth.
o Andrew Hockey succeeds Mark Routh as Chief Executive Officer and Mark Routh appointed Non-Executive
Chairman;
o Mark Hughes appointed as Chief Operating Officer;
o Fiona MacAulay appointed as independent Non-Executive Director (‘NED’) succeeding Andrew Hay who stepped
down as independent NED in February 2018;
o Rupert Newall appointed as Head of Corporate Finance; and
o At 31 December 2018, Fiona MacAulay succeeded Mark Routh as Non-Executive Chair.
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STRATEGIC REPORT FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
Highlights of 2018 (continued)
Financial
• Additional £10 million convertible loan facility signed with London Oil & Gas Limited (‘LOG’) on 21 February 2018,
with a further £15 million loan (not convertible) secured from LOG on 13 September 2018. As at 31 December 2018,
£7.85 million remains undrawn on the £15 million facility. A further £3.925 million was drawn in January 2019 and
£3.925 million outstanding remains.
• Cash balance at period end of £0.70 million.
• Post tax loss for the year was £5.64 million.
• Continue to progress funding process for Final Investment Decision (‘FID’) on Phase 1 of the core development,
including debt and equity discussions as well as an announced farm-out process to bring in an industrial partner.
• FID targeted for 1H 2019, with first gas targeted at the start of Q1 2021.
Post Year End Developments
• Fiona MacAulay was appointed Non-Executive Chair effective 1 January 2019.
• Robin Storey was appointed General Counsel and Company Secretary on 9 January 2019.
• Esa Ikaheimonen was appointed Non-Executive Director and Chair of the Audit Committee on 14 March 2019.
• On 4 January 2019, it was announced that the Financial Conduct Authority (‘FCA’) was investigating the affairs of
LCAF. LCAF was subsequently put into administration during February 2019. Furthermore, LOG entered
administration on 19 March 2019. In conclusion, it was envisaged the Company would not be adversely affected by
the administration of LOG and that the Company would continue to trade normally.
• The Company announced on the 25 February 2019 that it had initiated a focused farm-out process with a carefully
selected shortlist of motivated and well-funded potential farm-in partners.
• The Company announced on 5 March 2019 that it had received and promptly rejected an unsolicited pre-conditional
proposal from RockRose Energy plc (‘RockRose’) in respect of a possible cash offer for the entire issued share
capital of the Company at a price of 20 pence per Company share. Subsequently on 25 March 2019, the Company
announced that RockRose had approached the joint administrators of LOG to acquire the entire debt and accrued
interest due to LOG from the Company for the sum of £40 million in cash. The Board concluded to reject the proposal
unequivocally and continue to state that this subsequent offer is a further transparent attempt by RockRose to deny
both LOG’s and LCAF’s creditors, and by extension to LCAF’s mini-bond holders, of fundamental value, seeking
instead to reserve that value for the benefit of RockRose and those directly associated with RockRose. RockRose
withdrew their proposal on 1 April 2019.
• The Company announced on 1 April 2019 that it had conditionally placed 165,795,050 new ordinary shares of £0.01
each in the capital of the Company by way of a placing at a price of 10 pence per Ordinary Share to raise gross
proceeds of approximately £16.6 million. In addition, a further proposed issue of 3,250,000 new Ordinary Shares by
way of a subscription at a price of 10 pence per Ordinary Share by certain directors and key executives of the
Company. Furthermore, the Company announced that it intends to launch an open offer to shareholders to raise
approximately £2 million through the issue of approximately 20,000,000 new Ordinary Shares, also at an issue price
of 10 pence per share. This Fundraising is conditional, inter alia, upon the approval of shareholders at a general
meeting of the Company that will take place on or around 23 April 2019 and the admission of the relevant new
Ordinary Shares to London AIM.
• The Company announced on 1 April 2019, that concurrent to the Fundraising announcement above, the Company
has proposed to restructure its debt with LOG (in administration) by rescheduling by twelve months an amount of
£7.1 million of debt service due to LOG, the conversion of £1.64 million in interest due from LOG’s existing convertible
debt into new Ordinary Shares and a one year maturity extension to existing warrants being those 13,277,310
warrants which were granted by the Company in December 2015.
• The Skipper licence, P1609, was formally relinquished on 11 February 2019, as determined by the OGA.
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STRATEGIC REPORT FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
Health, Safety and Environment (‘HSE’)
The corporate HSE policies were reviewed, renewed and re-issued in anticipation of further Licence Round applications
during the year and the progressive selection and procurement of contracted services for the development of the Blythe
and Vulcan Satellites gas hub developments. The revised policies provide clear corporate expectation and direction
for the effective HSE planning and performance of activities.
The Company continued to develop its HSE organisation, arrangements and capabilities during the year. These
corporate developments formed a significant part of the demonstration of necessary operator competencies that were
submitted to the OGA in support of field licences for Blythe, Elgood, Nailsworth, Elland and Southwark. The
arrangements also support the Group’s applications in the OGA’s 30th Offshore Licensing Round.
The selection process of suitable contracted services for the engineering, design and operation of the Blythe and Vulcan
Satellites gas hub development incorporated appropriate HSE criteria and has been followed by the development and
implementation of HSE bridging documentation with both partnered and contracted enterprises, some of whom are
intended to undertake 'duty holder' responsibilities in the operations and maintenance of the Group’s eventual offshore
facilities, pipelines and wells.
Effective briefing and consultation with the regulatory authorities has been an essential activity during the year, in order
to assure compliance and to secure the necessary permits and consents for the range of project activities. This has
involved close contact with the OGA, HSE Pipelines Inspectorate and the BEIS Offshore Petroleum Regulator for
Environment and Decommissioning (‘OPRED’).
In preparation of statutory Environmental Impact Assessments (‘EIA’) that are required to support the Blythe and Vulcan
Satellites gas hub developments, an Early Consultation Document (‘ECD’) was circulated to over 40 identified potential
stakeholder parties, including oil & gas operators, windfarm operators, regulatory bodies, non-government organisations
(‘NGO’) and others with potential interest in the development. Responses to the ECD are being considered as our
project develops, and in the preparation of the formal EIAs that follow. The EIAs will themselves be subject to public
review and statutory consultation.
Business Strategy
The Company’s strategy is to target stranded gas assets and dormant discoveries, especially those near to existing
and ideally, owned infrastructure (the ’Hub Strategy’). These are assets that are no longer targets for the major oil and
gas companies but are potentially profitable developments which can be beneficially developed by a smaller
independent company, focused on the North Sea.
Given the steady rise of imported vs domestic gas in the UK over the last fifteen years and the country’s dependency
on gas for power, industry and heating, the maximising of gas resources in the North Sea makes strategic sense and
will help deliver energy security in the UK.
The aim is to build upon our existing gas portfolio in order to achieve a diversified and balanced portfolio of near and
long-term developments, ideally with appraisal upside that complements our existing operations. This will include the
acquisition of producing fields or near-term production if the risk is positively assessed and the acquisition price results
in value accretion. The Directors believe that there is a significant opportunity for the Company to exploit this strategy,
given that there are over 400 undeveloped and underdeveloped assets in the UK Continental Shelf (‘UKCS’).
The Hub Strategy targets strategic control over a number of dormant discoveries and appraisal assets that can be
developed through common existing infrastructure, thereby generating significant economies of scale. The Company
is executing this strategy in order to create UK SNS gas hubs with the acquisition of the Blythe licence, along with
operatorship, in addition to the acquisition of the Vulcan Satellites, the award of Licence P2342 (Nailsworth NW
Extension) in the 2016 29th Offshore Supplementary Licensing Round and the successful award of the Harvey, Harvey
South East, Goddard and Abbeydale licences in the 2018 30th Offshore Licensing Round.
The Company seeks to operate all its assets. Operatorship is strategically important for several reasons: firstly, third
party consents to tie in additional discoveries are easier to facilitate for operators of owned infrastructure. Secondly, as
the major oil and gas companies continue to divest late-life producing assets they often prefer to assign operatorship
and redeploy their own resources and so additional opportunities arise. Finally, in the UK licensing rounds, certain
licences will only be made available to pre-qualified operators.
Overall, the Board is confident that the Company has the management, experience and technical expertise to create
and seize new opportunities for future growth.
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STRATEGIC REPORT FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
Licences
The Company, through its wholly owned subsidiaries IOG North Sea Limited and IOG UK Limited is currently a licensee
on five Traditional Licences, two Promote Licences and four Innovate Licences all in the UK North Sea;
Licence
Blocks
Subsidiary
Interest
Discovery
Name
Licence
Type
Blythe/Elgood Hub
P1736
P2260
Harvey
P2085
P2441
48/22b ALL and
48/23a ALL
48/22c ALL
48/23c ALL and
48/24b ALL
48/24a
Vulcan Satellites Hub
P039
P2342
P130
P1915
49/21a J
48/25a ALL
48/25b NW
49/21c ALL
IOG North Sea Limited
100%
Blythe
Traditional
IOG North Sea Limited
100%
Elgood
Promote
IOG North Sea Limited
100%
Harvey
Promote
IOG North Sea Limited
100%
Harvey SE
Innovate A/C
IOG UK Limited
IOG UK Limited
IOG UK Limited
IOG UK Limited
100%
100%
100%
100%
Elland [1]
Nailsworth [2]
Nailsworth [2]
Southwark [3]
Traditional
Innovate C
Traditional
Traditional
Goddard
P2438
Abbeydale
P2442
Skipper
P1609
48/11c and 48/12b
IOG North Sea Limited
100%
Goddard
Innovate C
53/1b
IOG North Sea Limited
100%
Abbeydale
Innovate A/C
9/21a ALL
IOG North Sea Limited
100%
Skipper [4]
Traditional
[1] Formerly Vulcan East
[2] Formerly Vulcan North West
[3] Formerly Vulcan South
[4] Skipper relinquished 11 February 2019
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STRATEGIC REPORT FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
Licences (continued)
On 1 October 2018 Licences P2441 (Harvey SE) and P2442 (Abbeydale) commenced as Innovate A & C Licences and
Licence P2438 (Goddard) commenced as an Innovate C Licence. The Innovate Licence replaces several earlier types
of Seaward Production Licence: Traditional, Promote and Frontier. The Innovate Licence offers greater flexibility in the
durations of the Initial and Second Terms (which was the main difference between the older licence types). An applicant
for an Innovate Licence is able to propose the durations of the Initial and Second Terms, and among the permutations
that may be proposed are those that represent those associated with each of the older licence types.
The Initial Term can now be subdivided into up to three phases, with the Work Programme being correspondingly
divided:
• Phase A is a period for carrying out geotechnical studies and geophysical data reprocessing;
• Phase B is a period for undertaking seismic surveys and acquiring other geophysical data; and
• Phase C is for drilling.
Phases A and B are optional and depend on the applicant’s plans. Every Work Programme must have at least a Phase
C (just as a drilling commitment was the minimum Work Programme before the Innovate concept).
It remains the case that a Licence may only continue from the Initial Term into the Second Term if (among other things)
the Initial Term Work Programme has been completed and surrendered 50% of the initial acreage. Similarly, an Innovate
Licence may only continue from one Phase into another if that part of the Term Work Programme associated with the
earlier Phase has been completed and if the Licensee has committed to complete that part associated with the next.
When continuing into Phase C, the licensee must also demonstrate the technical and financial capacity to carry out the
Phase C part of the Work Programme.
In special cases where an applicant does not propose any exploration at all and proposes to develop an existing field
discovery or redevelop a field, a Licence may be awarded with no Initial Term; this is called a ‘Straight to Second Term’
Licence. Again, this was an option that was available before the Innovate concept.
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STRATEGIC REPORT FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
Statement of Reserves & Resources
SNS Hubs Reserves
SNS Portfolio
Gas Reserves
Condensate Reserves
Field
Blythe
Elgood
Total Blythe Hub
Nailsworth
Elland
Southwark
(BCF)
Blythe Hub
2P
33.0
21.7
54.7
3P
44.1
32.6
76.7
Vulcan Satellites Hub
2P
99.4
55.0
94.2
3P
147.2
72.9
137.7
1P
25.2
14.7
39.9
1P
60.4
39.9
61.2
Total Vulcan Satellites
Hub
161.5
248.5
357.8
Totals SNS Portfolio
201.4
303.2
434.5
Source: ERC Equipoise Competent Person’s Report 11 October 2017
Goddard Contingent Resources
(MMBbls)
2P
0.3
0.2
0.5
2P
1.0
0.0
0.1
1.2
1.7
3P
0.4
0.3
0.7
3P
1.5
0.1
0.1
1.7
2.4
1P
0.3
0.1
0.4
1P
0.6
0.0
0.0
0.7
1.1
Contingent Gas Resources
Discovery
Goddard
1C
54.3
(BCF)
2C
107.8
3C
202.8
Source: ERC Equipoise Competent Person’s Report 10 October 2018
Goddard Prospective Resources
Prospective Gas Resources
Prospect
Pop Up 1
Pop Up 2
Low
27.8
14.0
(BCF)
Best
48.8
24.2
High
81.5
39.9
Mean
52.3
25.9
Source: ERC Equipoise Competent Person’s Report 10 October 2018
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STRATEGIC REPORT FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
Statement of Reserves & Resources (continued)
Harvey Prospective Resources
Prospective Gas Resources
Discovery
Harvey
Low
85
(BCF)
Best
129
Source: Management Estimates: September 2018
Abbeydale Contingent Resources
Contingent Gas Resources
Discovery
Abbeydale
1C
5
(BCF)
2C
11
High
199
3C
24
Source: Management Estimates: September 2018
Skipper STOIIP and Resources
Discovered Oil Initially in Place
Contingent Resources
Field
(MMBbls)
(MMBbls)
Skipper [1]
P90
P50
P10
123.1
136.5
150.8
1C
17.9
2C
26.2
3C
34.9
[1] Relinquished 11 February 2019
Source: AGR Tracs CPR - September 2013.
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STRATEGIC REPORT FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
Operational Update
Thames Pipeline
The acquisition of the Thames Pipeline from Perenco UK Limited, Tullow Oil SK Limited and Spirit Energy Resources
Limited (Sale and Purchase Agreement, SPA1) completed on 16 April 2018.
On this date, the pre-acquisition costs for the Thames Pipeline and associated onshore Bacton Facility, previously held
as a prepayment in the books of the parent company, IOG plc, were brought across to IOG Infrastructure Limited. Also,
on this date, the Initial Thames Pipeline Decommissioning Security Amount of £500k was paid to Perenco UK. IOG
Infrastructure Limited is the owner, user, holder and operator of the pipeline under the Pipeline Works Authority (‘PWA’).
The MV Fugro Galaxy mobilised in late January 2018 and as part of its work programme carried out surveys along the
Thames Pipeline.
Preparation for the Intelligent Pigging Programme (‘IPP’) commenced on 20 February 2018 with onshore mechanical
preparation work at the Bacton Terminal. The main IPP work took place in May 2018 and early June 2018. Three 12m
pipeline sections were cut 60km offshore and retrieved to surface and indicated the pipeline to be in extremely good
condition. Two successful pipeline pressure tests confirmed pipeline integrity and initial 60km gauge pigging runs from
Bacton to the offshore tie-in point were successfully executed. The initial IPP run gathered insufficient data due to
technical malfunction with the pig and an alternative strategy was planned and presented to the HSE.
In September 2018, a crawler pig run was completed from Bacton to c.1km offshore demonstrating the viability of this
nearshore element of the line and the viability of the whole line and thus this export route was then confirmed by a 150
bar 24 hour hydrotest completed on 23 September 2019. Progress continued through 2H 2018 toward signing the
Sales and Purchase Agreement (SPA2) for the Thames Reception Facility with owners Perenco, Tullow and Spirit
Energy.
Other capital costs associated with the Thames Pipeline acquisition include potential tie-in studies (offshore → onshore),
the Crown Estate lease associated with the 12-mile onshore boundary (of which the Thames Pipeline lies in situ),
capitalised G&A and other directly attributable expenses.
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STRATEGIC REPORT FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
Operational Update (continued)
Blythe
The Blythe gas discovery in the Rotliegend Leman Formation, straddles Blocks 48/22b and 48/23a in the SNS in licence
P1736. IOGNSL has 100% working interest in and is operator. Blythe is planned to be developed with a single well tied
back to the Thames Pipeline via an unmanned platform (‘NUI’).
The MV Fugro Galaxy mobilised in late January 2018 and as part of its work programme carried out surveys across the
Blythe Hub (Blythe and Elgood fields) in support of field development. At Blythe this work included site surveys for
platform location and pipeline route surveys to the tie-in point at the Thames pipeline, and environmental sampling. The
Environmental Impact Assessment (‘EIA’) for the Blythe Hub was submitted on 31 January 2018 in line with milestones
agreed with the UK Oil & Gas Authority (‘OGA’).
During development engineering studies in 1H 2018, it was decided to split the development into two Phases with
Phase 1 development comprising Blythe, Elgood and Southwark and Phase 2 to include Nailsworth and Elland.
The Phase 1 Field Development Plan comprising Blythe, Elgood and Southwark was submitted to the OGA in August
2018 and following bilateral meetings was resubmitted in late October 2018 taking account of OGA comments. At year
end, FID and subsequent EIA and FDP approval was expected to occur in late Q1 2019 with first gas from Southwark
20 months later in Q4 2020 and Blythe first gas in early Q1 2021, subject to project financing.
In July 2018 Wood carried out FEED studies to assess costs and schedule for the tie-in lines to the Thames Pipeline
for the Phase 1 development including Blythe. In November 2018, offshore geotechnical surveys for the Blythe Platform
were completed alongside geotechnical surveys at Southwark and at Harvey, where a geophysical site survey was also
executed. Heerema also made progress with the FEED studies for the Blythe Platform in 2H 2018.
In December 2018 the initial Term of Licence P1736 containing Blythe was extended to 31 December 2019 subject to
the condition that an FDP capable of approval would be received by the OGA by 30 June 2019 and FID would occur by
30 September 2019.
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STRATEGIC REPORT FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
Operational Update (continued)
Elgood
IOGNSL has 100% working interest in and is operator of Licence P2260 (Block 48/22c), which was awarded in the 28th
Licensing Round. The licence, which lies immediately to the north-west of the Blythe licence, contains the Elgood
discovery in the Rotliegend Leman Sandstone.
Elgood is planned to be developed with a single well tied back subsea to the Thames Pipeline via a NUI at Blythe. The
MV Fugro Galaxy mobilised in late January 2018 and as part of its work programme carried out surveys across the
Blythe Hub (Blythe and Elgood fields) in support of field development. At Elgood this work included site surveys for
pipeline route surveys to the tie-in point at Blythe and environmental sampling. The EIA for the Blythe Hub was submitted
on 31 January 2018 in line with milestones agreed with the OGA.
The Phase 1 Field Development Plan comprising Blythe, Elgood and Southwark was submitted to the OGA in August
2018 and following bilateral meetings was resubmitted in late October 2018 taking account of OGA comments. At year
end, FID and subsequent EIA and FDP approval was expected to occur at end Q1 2019 with first gas at Southwark 20
months later in Q4 2020 and Elgood first gas in Q2 2021 subject to project financing.
In July 2018 Wood carried out FEED studies to assess costs and schedule for the tie-in lines to the Thames Pipeline
for the Phase 1 development including Elgood.
In January 2019 IOG received notification from the OGA that the drill or drop commitment for the initial Term of Elgood
Licence P2260 had been waived and the Licence could proceed into the Second Term, subject to the condition that an
FDP capable of approval would be received by the OGA by 30 June 2019 and FID would occur by 30 September 2019.
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STRATEGIC REPORT FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
Operational Update (continued)
Vulcan Satellites – Southwark, Elland and Nailsworth
The Vulcan Satellites are planned to be developed with NUIs at Southwark (three wells), Elland (two wells) and
Nailsworth (three wells) to the Thames Pipeline. All three satellites have their reservoirs in the Rotliegend Leman
Sandstone.
The MV Fugro Galaxy mobilised in late January 2018 and as part of its work programme carried out surveys across the
Vulcan Satellites Hub (Southwark, Nailsworth and Elland fields) in support of field development. This work included site
surveys for platform locations and pipeline route surveys to the tie-in point at the Thames Pipeline and environmental
sampling. The EIA for the Vulcan Satellites Hub was submitted in April 2018 in line with milestones agreed with the
OGA.
During development engineering studies in 1H 2018 it was decided to include Southwark as part of a Phase 1
development comprising Blythe, Elgood and Southwark.
The Phase 1 Field Development Plan comprising Blythe, Elgood and Southwark was submitted to the OGA in August
2018 and following bilateral meetings was resubmitted in late October 2018 taking account of OGA comments. At year
end, FID and subsequent EIA and FDP approval was expected to occur at end Q1 2019 with first gas at Southwark 20
months later in Q4 2020, subject to project financing.
In July 2018, Wood carried out FEED studies to assess costs and schedule for the tie-in lines to the Thames Pipeline
for the Phase 1 development including Southwark. In November 2018, offshore geotechnical surveys for the Southwark
platform were completed alongside geotechnical surveys at Blythe and at Harvey, where a geophysical site survey was
also executed. Heerema made progress with the FEED studies for the Southwark platform in 2H 2018 and FEED works
were also completed by ODE for the refurbishment at the Bacton Terminal.
Elland and Nailsworth, the other two Vulcan Satellites, will be part of Phase 2 of the development.
Given the development deferral of both Elland and Nailsworth (Phase 2), most current year 2018 fixed asset additions
have been attributable to the Southwark development area.
Further to the Vulcan East suspended well decommissioning paper, prepared by Acona in April 2015, IOGUKL believes
that the abandonment provision of £3.60 million continues to represent a reasonable cost estimate. Decommissioning
of this suspended well has been targeted as part of the Vulcan Satellites development program; however, as this
particular well is not assigned for development, this activity remains uncertain and may be further deferred subject to
agreement with the OGA.
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STRATEGIC REPORT FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
Operational Update (continued)
Harvey
IOGNSL has a 100% working interest in Licence P2085 to the east of Blythe (Blocks 48/23c & 48/24b) which was
awarded in the 27th Licensing Round and in Licence P2441 awarded in the 30th Licensing Round. These blocks contain
100% of the Harvey Structure with the reservoir targeted in the Rotliegend Leman Sandstone Formation.
In the first half of 2018 work on P2085 and adjacent open areas focused on reprocessing of existing 3D seismic data
to Pre-Stack Depth Migration level with Schlumberger WesternGeco to support the selection of a well location for the
firm Harvey well committed on P2085 in late 2017.
Following the completion of seismic reprocessing in July 2018, the dataset was reinterpreted and remapped. This
remapping led to a new volumetric assessment of gross unrisked Prospective Resources (as estimated by
management) at Harvey of 85-129-199BCF (Low-Mid-Best Estimate) versus the 2017 CPR estimate of 45-114-
286BCF. Management’s assessment of Geological Chance of Success at Harvey is 63%. The gross volumes were
secured by IOG with the award of Licence P2441 (SE Harvey) in the 30th UKCS Offshore Licensing Round, with licence
commencement on 1 October 2018. Under the licence a firm commitment was made to the Oil and Gas Authority
(“OGA”) to reprocess 87km2 of 3D seismic to PSDM and drill a well to 2,345m TD or drop the Licence.
In support of the Licence P2085 firm well commitment a Letter of Intent was signed with Ensco for the Ensco 72 Jack-
Up Drilling Unit for the drilling of a Harvey appraisal well in 2019 to be spud before 20 September 2019. Halliburton are
under LOI to provide well services and Fraser Well Management were identified as drilling operator. Technical work
proceeded to the point where a well location was selected for the Harvey well in October 2018 and permitting and
planning to drill the well in 1Q 2019 subject to funding were advanced.
All costs associated with developing the Harvey SE extension are now incorporated within the main Harvey licence
P2085, as determined by one single field area. Management will continue to account for any minor licence admin costs
(licence fee, OGA levy etc.) associated with P2441 separately.
Resources in the other discoveries and prospects on the Harvey area blocks will be subject to evaluation and appraisal
following the results of the 3D seismic reprocessing.
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STRATEGIC REPORT FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
Operational Update (continued)
Goddard
On 23 May 2018, IOG was offered Blocks 48/11c & 48/12b in the 30th UKCS Licensing Round and accepted the offer
as Provisional Licence P2438 which contains Goddard, hitherto known as Glein, a dormant gas discovery.
Licence P2438 formally commenced on 1 October 2018. Under the licence a firm commitment was made to the Oil and
Gas Authority (“OGA”) to reprocess 175 km2 of 3D seismic to PSDM and drill an appraisal well on Goddard to 3,140m
TD within three years.
In the second half of 2018 work on Goddard focused on securing access to 3D seismic data processed to PSDM level
across the Goddard licence. This dataset was secured from a previous operator. On licence commencement it was
decided to submit the work done to date to ERC Equipoise, as the Competent Person, for audit purposes. Based on
the 30th Round Licence Application document, management estimates of Contingent Resources were 1C/2C/3C
45/189/396BCF. ERC Equipoise completed their work and assessed gross unrisked 1C/2C/3C Contingent Resources
of 54.3/107.8/202.8 BCF and Low/Best/High gross unrisked prospective gas resources are 41.8/73.0/121.4 BCF. The
CPR assesses the geological chance of success of the prospective gas resources at 48%. The chance of development
of Goddard is estimated by ERC Equipoise as being 75%.
In the light of the relative maturity of Goddard’s Contingent Resources it was decided in early 2019 to commence
Goddard FDP planning and to include Goddard in Phase 1 Core development planning.
Abbeydale
On 23 May 2018, IOG was offered Block 53/1b in the 30th UKCS Licensing Round and accepted the offer as Provisional
Licence P2442 which contains the Abbeydale dormant gas discovery, hitherto known as Aberdonia, which was
discovered in 1996. Licence P2442 formally commenced on 1 October 2018. Under the four-year Licence, a
commitment was made to reprocess 150 km2 3D seismic data to PSDM and drill a well to 1,960m TD or drop the licence.
2H 2018 work focused on securing prices for 3D reprocessing.
Management estimates contingent resources on Abbeydale are 1C/2C/3C 5/11/24 BCF. The new 3D seismic work
programme is expected to increase these estimates to more commercial levels with a view to tying into IOG’s Thames
Pipeline as the export route.
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STRATEGIC REPORT FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
Operational Update (continued)
Skipper
The Skipper licence, P1609, was formally relinquished on 11 February 2019, as determined by the OGA.
Asset Acquisitions
The Company continues to assess the potential for the acquisition of a number of assets, particularly those already in
production, to support the wider development and growth of the business.
Key Performance Indicators
The Group’s main business is the acquisition and exploitation of oil and gas acreage. Non-financial performance is
tracked through the accumulation of licence interests followed by the successful discovery and exploitation of oil and
gas reserves as indicated through prospective, contingent and proved reserves inventories. Financial performance is
tracked through the raising of finance to fund proposed programmes and the control of costs against budgets.
Principal Risks and Uncertainties
The Group operates in the oil and gas industry, an environment subject to a range of inherent risks and uncertainties.
Being at an early stage the prime risks to which the Group is subject are the access to sufficient funding to continue its
operations, the status and financing of its partners, changes in cost and reserves estimates for its assets, changes in
forward commodity prices and the successful development of its oil and gas reserves. Key risks and associated
mitigation are set out below.
Investment Returns: Management seeks to raise funds and then to generate shareholder returns through
investment in a portfolio of exploration and development acreage leading to the drilling of wells, the discovery of
commercial reserves followed by their exploitation. Delivery of this business model carries several key risks.
Risk
Mitigation
Market support may be eroded obstructing
fundraising and lowering the share price
• Management regularly communicates its strategy to
shareholders
General market conditions may fluctuate
hindering delivery of the Company’s
business plan
• Focus is placed on building an asset portfolio capable of
delivering regular news flow and offering continuing
prospectivity
• Management aims to retain adequate working capital and
secure finance facilities sufficient to ride out downturns
should they arise
Each asset carries its own risk profile and
no outcome can be certain
• Management aims to avoid over-exposure to individual
assets and to identify the associated risks objectively
Company may not be able to raise funds to
exploit its assets or continue as a going
concern
• Management is pursuing specific and appropriate plans for
funding the development of its asset portfolio and is
confident in a successful outcome
Company has given security over its assets
to its lender, LOG
• Progress is ongoing with these potential funding routes and
on 1 April 2019 the Company announced a fund raise of
£16.6m (gross) as well as a concurrent amendment to the
term of £7.1m of LOG loan notes. As set out in Note 1 the
Group will require additional funding within the next twelve
months in order to meet its working capital needs,
development plans and loan repayment schedule.
• Management is in discussion with the Administrators of LOG
who have acknowledged the importance of developing the
Company’s assets in order to return value to LCAF bond
holders. The LOG shareholders have made public
announcements of their intention to continue to support the
Group and that the Group’s ongoing operations are not
adversely affected by the LOG Administration.
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STRATEGIC REPORT FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
Principal Risks and Uncertainties (continued)
Operations: Operations may not go to plan, leading to damage, pollution, cost overruns and poor outcomes
Risk
Mitigation
Individual wells may not deliver recoverable
oil and gas reserves
•
Thorough pre-drill evaluations are conducted to identify the
risk/reward balance
Operations may take far longer or cost more
than expected
Resource estimates may be misleading
curtailing actual reserves recovered
• Exposure selectively mitigated through farm-out
• Management applies rigorous budget control
• Adequate working capital is retained to cover reasonable
eventualities
•
The Group deploys qualified personnel
• Regular third-party reports are commissioned
• A prudent range of possible outcomes are considered within the
planning process
Licensing & Regulation: The Group may be unable to meet its licence and regulatory obligations
Risk
Mitigation
UKCS Licences may be revoked
• Continue thorough communications with the OGA to determine
licence status and meet requirements
Personnel: The Company relies upon a pool of experienced and motivated personnel to identify and execute
successful investment strategies
Risks
Mitigation
Key personnel may be lost to other
companies
Difficulty in attracting the necessary talent as
the Group moves into development of its
projects
•
•
The Remuneration Committee regularly evaluates
incentivisation schemes to ensure they remain competitive
The Group continues to review and adopt attractive packages
for both staff and contractors
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STRATEGIC REPORT FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
Principal Risks and Uncertainties (continued)
Commercial environment: World and regional markets continue to be volatile with fluctuations and infrastructure
access issues that might hinder the Company’s business success
Risk
Mitigation
Volatile commodity prices mean that the
Company cannot be certain of the future sales
value of its products
Brexit
The Group may not be able to get access, at
reasonable cost, to infrastructure and product
markets when required
• Price mitigation strategies may be employed at the point of
major capital commitment
• Gas may be sold under long-term contracts reducing exposure
to short term fluctuations
• Oil and gas price hedging contracts may be utilised where
viable
• Budget planning considers a range of commodity pricing
•
The Group does not see Brexit having a significant impact on
its business model – the Company’s production will be
indigenous, and the UK gas market is not forecast to be
significantly directly impacted by an exit from the EU, being a
substantial core element of UK primary energy demand.
However, access to overseas personnel and equipment may be
affected to a greater or lesser extent, depending on the precise
Brexit outcome
• A range of different off-take options are pursued wherever
possible
Credit to support field development
programmes may not be available at
reasonable cost
•
The Company seeks to build and maintain strong banking
relationships and initiates funding discussions at as early a
stage a practicable
Corporate Hedging Strategy and Implementation
The primary objective of the Company’s hedging policy is to protect projected future cash flows, generated from
operations, against unforeseen changes in short and medium-term market conditions.
No hedging instruments were utilised during 2018 in view of the limited exposures carried during the year. As the
Company’s capital investment programmes increase, hedging will be carried out in a simple and cost-effective manner,
retaining exposure to upside but avoiding any speculative exposure to commodity prices or exchange rates. The
application of the policy is within a range to require exercise of management judgement in the light of market conditions
and business variables.
Details of the risks arising from the Group’s use of financial instruments can be found in Note 20 to the financial
statements.
Insurance
The Group insures the risks it considers appropriate for the Group’s needs and circumstances. However, the Group
may elect not to have insurance for certain risks, due to the high premium costs associated with insuring those risks or
for various other reasons, including an assessment that the risks are remote.
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STRATEGIC REPORT FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
Finance Review
Income Statement
The Group made a loss for the year of £5.64 million (2017 – £2.75 million).
Further post 2016 well drilling expenses on the Skipper asset, resulted in an impairment charge to the Income Statement
of £184k (refer Note 8). There was no other impairment made against oil and gas properties during the year. This
compares with the £119k impairment charged in 2017 which included £85k for Skipper post well drilling expenses
together with £34k on the relinquishment of Licence P2122.
A charge of £922k (2017: £430k) to the Income Statement reflects the expenses incurred for pre-licence activity,
business development (‘BD’) and other corporate project activity and expenses.
Administration expenses of £974k (2017 – £700k) for the year comprise gross general and administration (‘G&A’)
expenses of £3.19 million (2017 - £2.12 million) including non-cash share-based payment expense of £378k (2017 -
£298k), net of both the allocation of £702k (2017 - £666k) attributable to pre-licence activity, BD and other corporate
projects, as included in the £922k above, and the allocation of £1.52 million (2017 - £757k) capitalised to assets
throughout the Group. The increase in gross G&A expenses highlights the further significant increase in resource
required to support the Group’s accelerating SNS capital projects and other capital activities during the year.
The net loss on settlement of liabilities of £106k (2017: £1k) reflects both realised and unrealised movements on the
settlement of liabilities via the issue of shares.
The foreign exchange loss of £334k (2017: gain £333k) reflects foreign exchange movements on non-GBP denominated
loans, provisions and trade creditors.
Finance expense of £3.12 million (2017 – £1.83 million) includes accrued interest payable on loans (net of capitalised
interest £752k (2017 - £22k)), discount accretion and both current and amortised finance expenses. These expenses
relate to fees and interest incurred on both loan finance facilities and those trade creditors subject to deferred payment
and equity conversion terms.
Balance Sheet
PPE oil and gas assets have increased to £41.53 million (2017: £21.32 million) during the year, which represents capital
expenditure on Front End Engineering Design (‘FEED’), the Thames Pipeline acquisition and other pre-development
activities with respect to Blythe, Elgood and the Vulcan Satellites. The £20.21 million increase includes the Thames
Pipeline acquisition, pigging operations and other associated onshore and offshore pipeline engineering studies. The
Group also completed several subsea activities including surveys on all pre-development pipeline routes together with
subsurface geotechnical surveys for both Blythe and Southwark. Other capital cost drivers included further platform
studies and miscellaneous pre-FID work programmes associated with the dual hub development strategy.
The Harvey, Goddard and Abbeydale exploration and evaluation (‘E&E’) assets represent the E&E portfolio at 31
December 2018, with a net book value of £2.35 million (2017: £185k) to the Group at 31 December 2018. This increase
essentially consists of capital costs associated with the aforementioned Harvey appraisal well, including geophysical,
geotechnical and well site surveys and pre-drill engineering and planning.
Current assets have increased to £1.37 million (2017: £1.11 million) mainly resulting from an increase in cash resources
of £557k to £702k and recognition of prepaid financing costs of 291k. This prepayment includes miscellaneous direct
financing fees incurred with regard to the Company’s debt and equity funding efforts.
Total liabilities have increased to £51.07 million (2017: £27.40 million) mainly resulting from further drawings on the
loans provided by London Oil & Gas Limited (‘LOG’) (see table below). Total liabilities comprise LOG Loan facilities of
£34.03 million (2017: £13.00 million) offset by £4.21 million (2017: £0.61 million) loan finance costs, Skipper deferred
trade creditors of £2.22 million (2017: £4.46 million), SNS Project creditors £3.41 million (2017: £0.18 million), other
creditors £0.32 million (2017: £0.19 million), deferred consideration in relation to acquisitions of £6.19 million (2017:
£6.01 million), the Vulcan East suspended well abandonment provision of £3.60 million (2017: £3.60 million), the
Thames Pipeline decommissioning provision of £2.04 million (2017: £nil) and accruals of £3.47 million (2017: £0.57
million).
Cash Flow
Net cash outflows of £3.04 million (2017: £1.05 million) from operations, £14.82 million (2017: £3.40 million) from
investing activities and £0.43 million (2017: £2.03 million) from loan repayments and financing activities were funded
via loan drawings and the issue of equity instruments in the Company totalling £18.85 million (2017: £6.38 million).
The Directors will not be recommending payment of a dividend.
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STRATEGIC REPORT FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
Finance Review (continued)
London Oil and Gas Limited and GE Oil and Gas UK Limited Loans
• 4 December 2015 - the Company secured agreement for a loan of £2.75 million from LOG in parallel with a
£2.00 million loan from GE Oil & Gas UK Limited (‘GE’);
• 11 December 2015 - a further loan of £0.80 million was provided by LOG;
• 5 February 2016, a further £10.00 million loan was provided by LOG, convertible at 8p;
• 21 February 2018, a further £10.00 million loan was provided by LOG, convertible at 19p; and finally
• 13 September 2018, a further £15.00 million loan was provided by LOG.
On 21 December 2017, both the outstanding GE loan and GE Skipper creditor (provision of wellhead equipment and
services) were renegotiated under the terms of a Conversion Deed (‘CD’) and a Deferred Payment Deed (‘DPD’)
allowing circa 50% of the total outstanding liability to be converted to equity, with the remaining liability to be settled in
cash. Similar CD and/or DPD arrangements were negotiated for all other remaining Skipper creditors which resulted in
a total of £1.98 million being subject to conversion with a further £2.44 million and USD 2.75 million to be settled in
cash, with an original settlement date of 31 August 2018.
The LOG loans are secured over the Group’s assets and are due to be redeemed thirty-six months following each
individual drawdown. All outstanding LOG debt is redeemable after 31 December 2018. Interest of LIBOR + 9% per
annum accrues on a cumulative monthly basis on each drawdown, other than the £15.00 million loan which accrues
interest at the higher rate of LIBOR + 11% from 1 December 2018.
LOG
LOG
LOG
LOG
LOG
Facility Amount
(£ million)
2.75
0.80
10.00
10.00
15.00
£38.55
Table 1: Summary Loans with LOG
Available until
Interest rate
Warrants / Convertible details
Repayment by
31 Dec-19
LIBOR + 9%.
5,777,310 warrants @ 11.9p
36 months from drawing
31 Dec-19
LIBOR + 9%.
7,500,000 warrants @ 8p
36 months from drawing
31 Dec-19
LIBOR + 9%.
8p conversion price
36 months from drawing
21 Feb-22
LIBOR + 9%
19p conversion price
36 months from drawing
13 Mar-19
LIBOR + 9% /
11% wef 1 Dec-
18
20,000,000 warrants @ 32.18p
36 months from drawing
All Conditions Precedent to the LOG loans have been met and have been drawn with agreement from LOG.
The aim of the £10.00 million LOG loan from February 2016 was to support G&A expenditures, together with
acquisitions in the endemic oil and gas E&P sector low-price environment, but also organic growth. During 2016, the
additional 50% acquisition of the Blythe licence was funded from this facility, together with the acquisition of Oyster
Petroleum Limited (renamed IOG UK Limited), incorporating the Vulcan Satellite assets. The loan, including accrued
interest, may be converted into new ordinary Company shares at a price of 8p per share at LOG’s election prior to
repayment. This loan has a coupon of LIBOR + 9%, which is deferred until maturity.
The main purpose of the £10.00 million loan from February 2018 was to support G&A expenditures, repay outstanding
Skipper creditors and to fund the Group through to Final Investment Decision (‘FID’) on its SNS development projects.
The loan, including accrued interest, may be converted into new ordinary Company shares at a price of 19p per share
at LOG’s election prior to repayment. This loan has a coupon of LIBOR + 9%, which is deferred until maturity.
The main purpose of the £15.00 million loan from September 2018 was to fund the drilling of the Harvey appraisal well,
repay outstanding Skipper creditors which had been further deferred, and cover ongoing overheads. The loan was
issued together with 20,000,000 warrants which may be converted into new ordinary Company shares at LOG’s election
at a warrant subscription price of 32.18p, prior to the maturity date of 13 September 2023.
The Group had £34.03 million borrowings outstanding on its LOG facilities at 31 December 2018 (2017 - £13.00 million)
including accrued interest. It had in place further undrawn debt from the LOG facilities of a total £7.85 million, excluding
accrued interest, at that date. A further £3.925 million was drawn in January 2019 and £3.925 million outstanding
remains. The Company notes that at time of writing London Oil and Gas Ltd has been placed into administration as has
London Capital and Finance, from whom LOG secured loan finance to provided IOG’s funding above. The Company
has engaged with LOG and LCAF administrators who have stated publicly that they will support IOG and the LOG/LCAF
administration process will have no impact on the Company’s business.
The Company has recently announced the rescheduling by 12 months, initially to January 2020, of £7.1 million of debt
service due to LOG over the course of 2019, the conversion of £1.64 million of interest due from LOG’s existing
convertible debt into new Ordinary Shares and a 12-month maturity extension pursuant to those 13,277,310 warrants
that were issued to LOG by the Company in December 2015.
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CORPORATE GOVERNANCE
Board of Directors
The Company is led by a strong, disciplined Board with extensive experience in all aspects of the Company’s business
supported by a capable and experienced management team. Their experience covers both ends of the investment spectrum
from private equity backed start-up companies to FTSE-100 listed companies. The Board is supported by a capable and
experienced management team.
Fiona MacAulay – Non-Executive Chair (appointed 10 July 2018)
A Chartered Geologist with over 30 years’ experience in the Upstream oil and gas sector including key roles in a number of
leading oil and gas firms across the large, mid and small cap space including Mobil, British Gas, Amerada Hess and
Rockhopper. Non-Executive Director at Coro Energy plc. Currently serving as the European President of the American
Association of Petroleum Geologists.
Andrew Hockey – Chief Executive Officer (appointed 20 March 2017)
Having worked in the industry for 36 years, Andrew Hockey has significant sector experience. He has a technical background
with a degree in geology from Oxford University, and a master’s degree in petroleum geology from Imperial College London.
Until the end of 2015 Andrew was General Manager of Business Development at UKCS oil and gas exploration and production
company Fairfield Energy Limited which he helped to found in 2005. Andrew led the team to acquire Clipper South as an
undeveloped discovery from Shell and Esso and then subsequently managed its development via farm down and funding
through to first gas in 2012. Andrew is now a non-executive director of Fairfield Energy and a founder of its parent company,
Decom Energy Limited. Andrew has also served on the board of AIM-listed Sound Energy plc, an upstream company with
onshore interests in Italy and Morocco, where he was a Non-Executive Director from 2011-2015 and Chairman from 2012-
2014.
Martin Ruscoe – Non-Executive Director (appointed 9 February 2016)
Martin has over 40 years' experience in the Financial Services Industry. Martin initially worked for a top 20 life assurance
company for 25 years, the last 9 years as Chief Investment Officer being involved in all forms of investment, taxation and new
product development within the company. Following a takeover, he left to move to the broking side of the investment
community working for Swiss Bank, Citicorp and Smith New Court. Martin then spent 12 years with Charterhouse Securities
who were voted number one in the small cap market and then spent 6 years with Seymour Pierce, at the time, the largest AIM
Broker in London. He has vast experience and has overseen more than 200 institutional fund raisings including new listings,
placings and rights issues. His current Non-Executive Director positions include: LOG, London Power Corporation plc and
the Company. Following the investments by LOG into the Group, Martin is an appointed LOG Board representative pursuant
to the execution of the LOG loan agreements.
The Rt. Hon. Charles Hendry – Non-Executive Director (appointed 20 March 2017)
Charles Hendry was Minister of State for Energy from May 2010 until September 2012. Since leaving ministerial office he
has undertaken a wide range of roles, including as President of the British Institute of Energy Economics, chair of the Forewind
Consortium from 2013-2015, and in 2016 he was appointed by the UK Government to lead a review into the strategic case
for tidal lagoons and their role in the UK energy mix. His current Non-Executive Director positions include: LOG, London
Power Corporation plc and the Company. Following the investments by LOG into the Group, Charles Hendry is an appointed
LOG Board representative pursuant to the execution of the LOG loan agreements.
Mark Hughes – Chief Operating Officer (appointed 18 April 2018)
Mark started his career at Shell International Exploration and Production in a number of roles including Head of Topsides
Design for the Sole Pit Compression Project. Mark was Group Development Engineering Manager for Lasmo UK plc and
Group E&P Exploration and Operations Manager for Gaz de France, Paris. He was also Managing Director of GDF Britain
and GDF Country Manager. He was founder and CEO of Hibernia Energy, an independent Southern North Sea focussed gas
developer. Mark was made Head of Development for RWE Dea UK where he was responsible for the RWE operated North
Sea Breagh and Clipper South Developments from inception to first gas, representing some £880 million gross investment.
Upon the sale of RWE Dea UK to INEOS, Mark was made Commercial Director UK at INEOS Breagh. Mark is a Chartered
Member of the Institute of Mechanical Engineers and has a technical background with a first-class Honours degree in Civil
Engineering from the University of Southampton.
Esa Ikaheimonen - Non-Executive Director (appointed 14 March 2019)
Esa has over 25 years of oil and gas industry experience and strong board level expertise. He is currently the CFO of London
listed E&P company Genel Energy plc and a Non-Executive Chairman of Lamor Corporation, a leading environmental service
company. Esa’s previous non-executive experience includes roles at Ahlstrom Corporation, global supplier of fibre-based
products, and at Vantage Drilling International, a major offshore drilling contractor. Previously, in addition to these non-
executive roles, Esa was Executive Vice President and CFO of Transocean, the world’s largest offshore drilling company.
Prior to Transocean, Esa enjoyed a 20-year career at Royal Dutch Shell, culminating in the role of Vice President Finance for
Shell Africa E&P. He holds a master’s degree in Law from the University of Turku, specialising in tax law and tax planning. As
Senior Independent Non-Executive Director, Esa will chair the Company’s Audit Committee and serve on the Remuneration
and Nominations committee.
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CORPORATE GOVERNANCE (CONT’D)
Remuneration Policy
Remuneration comprises a mix of salary payments and equity incentives. During the initial investment phase, the mix
is weighted towards incentives rather than cash payments.
Options and Long-Term Incentive Plan Policy
The Board believes that it is important that employees of the Group (including executive directors) are appropriately
and properly motivated and rewarded, with the success of the Group dependent to a significant degree on the future
performance of the executive management team. Accordingly, the Board has adopted the Long-Term Incentive Plan
(‘LTIP’) allowing the Company to grant to directors and employees options over ordinary shares. The LTIP is
administered by the Remuneration Committee and the maximum aggregate awards under the LTIP, together with any
other employee share schemes, cannot exceed ten per cent of the issued share capital of the Company at the time of
grant.
Salary Sacrifice Arrangements
The Directors may establish further share incentive arrangements for the benefit of the Group’s employees in the future.
Any options to be granted under any such share incentive arrangements will be at the discretion of the Remuneration
Committee. Options may also be granted to both non-executive directors and consultants.
During the year, resulting from cash constraints on the Company and a desire to ensure that these limited resources
were focussed on operations, the service agreements of personnel were varied such that cash payments were reduced,
and the difference settled by options granted with a strike price of 1p. The number of options granted is determined by
the Company’s volume weighted average share price for each six-month period of salary or fee sacrifice. Further details
can be found in Notes 4 and 16 to the financial statements.
Corporate Governance Statement
The Directors recognise the importance of sound corporate governance. The Company has adopted the Quoted
Companies Alliance Corporate Governance Code (“Code”) to the extent considered appropriate for a company of its
size.
The ten ‘Principles of the Code’ are set out below with details as to how the Company complies with each principle and
explanations of why if it does not.
DELIVER GROWTH
1. Establish a strategy and business model which promote long-term value for shareholders
The Company’s strategy is to target stranded assets and dormant discoveries, especially those near to existing and
ideally, owned infrastructure (the ‘Hub Strategy’). These are assets that are no longer targets for the major oil
companies but are potentially profitable developments which can be beneficially developed by a smaller independent
company, focused on the North Sea.
Given the steady rise of imported vs domestic gas in the UK over the last decade and the country’s dependency on gas
for power, industry and heating, the maximising of gas resources in the North Sea makes strategic sense and will help
deliver energy security in the UK.
The aim is to build upon the existing development gas assets in order to achieve a diversified and balanced portfolio of
near and long-term developments, ideally with appraisal upside that complement the existing operations. This will
include the acquisition of producing fields or near-term production if the risk is positively assessed and the acquisition
price results in value accretion. The Directors believe that there is a significant opportunity for the Company to exploit
this strategy, given that there are over 400 undeveloped and underdeveloped assets in the UK Continental Shelf
(‘UKCS’).
The Hub Strategy targets strategic control over a number of dormant discoveries and appraisal assets that can be
developed through common existing infrastructure, thereby generating significant economies of scale. The Company
also acquires low cost development ready assets through the Licensing Round system and has been active in all UKCS
Licensing Rounds since the Company was formed.
The Company seeks to operate all its assets. Operatorship is strategically important for several reasons: firstly, third
party consents to tie in additional discoveries are easier to facilitate for operators of owned infrastructure. Secondly, as
the major oil companies continue to divest late-life producing assets they often prefer to assign operatorship and
redeploy their own resources and so additional opportunities arise. Finally, in the UK licensing rounds, certain licences
will only be made available to pre-qualified operators.
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CORPORATE GOVERNANCE (CONT’D)
Corporate Governance Statement (continued)
Overall, the Board is confident that the Company has the management, experience and technical expertise to create
and seize new opportunities for future growth.
This Business Strategy is communicated and updated annually in the Annual Report and Accounts.
2. Seek to understand and meet shareholder needs and expectations
The Company remains committed to listening and to communicating openly with its shareholders to ensure that its
strategy, business model and performance are clearly understood. Understanding what analysts and investors think
about the Company and in turn, helping these audiences understand our business, is a key part of driving our business
forward and we actively seek dialogue with the market.
We do so via investor roadshows, attending investor conferences, hosting capital markets days, our website and our
regular reporting.
Private shareholders
The AGM is the main forum for dialogue with shareholders and the Board. The Notice of Meeting is sent to shareholders
at least 21 days before the meeting. The Directors routinely attend the AGM and are available to answer questions
raised by shareholders. For each vote, the number of proxy votes received for, against and withheld is announced at
the meeting. The outcome of the resolutions proposed at the AGM are subsequently published on the Company’s
corporate website.
To contact the Company, please email: info@independentoilandgas.com
Institutional shareholders
The Directors actively seek to build a relationship with institutional shareholders. Shareholder relations are managed
primarily by the Chief Financial Officer, supported by the Chief Executive Officer, as appropriate. The Chief Executive
Officer and Chief Financial Officer make presentations to analysts throughout each year and immediately following the
release of the full-year and half-year results.
The Board is kept informed of the views and concerns of major shareholders by briefings from the Executive Team.
Any significant investment reports from analysts are also circulated to the Board. The Non-Executive Chair and Senior
Independent Director are available to meet with major shareholders if required to discuss issues of importance to them.
A form to contact the Company is available on the Company website. To request any information or meetings please
contact: info@independentoilandgas.com
General Market Updates
The Company makes regular updates to the market on its commercial progress at all stages of executing on its strategy.
3. Consider wider stakeholder and social responsibilities and their implications for long- term success.
Engaging with our stakeholders strengthens our relationships and helps us make better business decisions to deliver
on our commitments. The Board is regularly updated on wider stakeholder engagement feedback to stay abreast of
stakeholder insights into the issues that matter most to them and our business and to enable the Board to understand
and consider these issues in decision-making.
Employees
We have: -
Introduced a Maternity Policy
Our maternity pay policy is for an employee taking maternity leave to receive six weeks at 100% pay and a further
seven weeks at 50% pay followed by 26 weeks during which they will receive Statutory Maternity Pay. A further 13
weeks unpaid leave may be taken.
Developed a Staff Handbook
Following a significant increase in staff numbers over the past year, we have written a staff handbook to improve the
communication of the Company’s principles and policies with our staff and contractors. It encapsulates the Company’s
Code of Conduct by which all staff and contractors are expected to comply.
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CORPORATE GOVERNANCE (CONT’D)
Corporate Governance Statement (continued)
Suppliers
Over the past year we have: -
Developed a Supply Chain Action Plan as required by the OGA.
As part of the process to submit Field Development Plans to the Oil & Gas Authority, the Company has developed a
Supply Chain Action Plan.
Health, Safety and Environment (‘HSE’)
Over the past year, the corporate HSE policies were reviewed, renewed and re-issued. These policies support further
Licence Round applications during the period and the progressive selection and procurement of contracted services for
the development of the Blythe and Vulcan Satellites gas hub developments. The revised policies provide clear
corporate expectation and direction for the effective HSE planning and performance of activities.
The Health and Safety Policy and the Environmental Management Policy are published on the Company Website and
both are displayed in the Company’s offices.
The Company has continued to develop its HSE organisation, arrangements and capabilities. These corporate
developments formed a significant part of the demonstration of necessary operator competencies that were submitted
to the OGA in support of our field licences. The arrangements also support applications in the OGA Licensing Rounds.
Selection of suitable contracted services for the engineering design and operation of the Blythe and Vulcan Satellites
gas hub development incorporated suitable HSE criteria and has been followed by the development and implementation
of HSE bridging documentation with our partnered and contracted enterprises, some of whom are intended to undertake
'duty holder' responsibilities in the operations and maintenance of our eventual offshore facilities, pipelines and wells.
Effective briefing and consultation with the regulatory authorities has been an essential activity during the period, in
order to assure compliance and secure necessary permits and consents for the range of project activities. This has
involved close contact with the OGA, HSE Pipelines Inspectorate and the BEIS Offshore Petroleum Regulator for
Environment and Decommissioning (‘OPRED’).
To aid preparation of the statutory Environmental Impact Assessments (‘EIA’) that are required to support our Blythe
and Vulcan Satellites gas hub developments, an Early Consultation Document (‘ECD’) was circulated to over 40
identified potential stakeholder parties, including oil & gas operators, windfarm operators, regulatory bodies, non-
government organisations (‘NGO’) and others with potential interest in the development. Responses to the ECD are
being considered as our project develops and in the preparation of the formal EIAs that follow. The EIAs will themselves
be subject to public review and statutory consultation.
MAINTAIN A DYNAMIC MANAGEMENT FRAMEWORK
4. Embed effective risk management, considering both opportunities and threats, throughout the
organisation
Audit, risk and internal control
The Board of Directors are aware of their responsibility for establishing and communicating a system to manage risk
and implement internal controls.
Operational risks are identified and assessed by management and any significant risks are reported to the Board.
Financial and commercial risks are reviewed by the Board.
The Company’s internal control systems are designed to provide the directors with reasonable assurance that any
problems are identified on a timely basis and dealt with appropriately. The Board considers the internal controls to be
effective, but no system of internal control can provide absolute assurance against material misstatement or loss.
The Company will effectively review the risks faced by the business, considering both opportunities and threats and
identify these in its annual report.
Further disclosures on risk and internal controls are set out below.
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CORPORATE GOVERNANCE (CONT’D)
Corporate Governance Statement (continued)
Key Performance Indicators
The Group’s main business is the acquisition and exploitation of oil and gas acreage. Non-financial performance is
tracked through the accumulation of licence interests followed by the successful discovery and exploitation of oil and
gas reserves as indicated through prospective and contingent resources and proved reserves inventories. Financial
performance is tracked through the raising of finance to fund proposed programmes and the control of costs against
budgets.
Principal Risks and Uncertainties
The Group operates in the oil and gas industry, an environment subject to a range of inherent risks and uncertainties.
Being at an early stage, the prime risks to which the Group is subject are the access to sufficient funding to continue its
operations, the status and financing of its partners, changes in cost and reserves and resources estimates for its assets,
changes in forward commodity prices and the successful development of its oil and gas reserves.
Key risks and associated mitigation
Investment Returns
Management seeks to raise funds and then to generate shareholder returns though investment in a portfolio of
exploration and development acreage leading to the drilling of wells and the discovery of commercial reserves, followed
by their exploitation. Delivery of this business model carries several key risks.
Risk
Mitigation
Market support may be eroded obstructing
fundraising and lowering the share price
regularly communicates
• Management
shareholders
Focus is placed on building an asset portfolio capable of
delivering regular news
flow and offering continuing
prospectivity
its strategy
to
•
General market conditions may fluctuate
hindering delivery of
the Company’s
business plan
• Management aims to retain adequate working capital and
secure finance facilities sufficient to ride out downturns
should they arise
Each asset carries its own risk profile and
no outcome can be certain
• Management aims to avoid over-exposure to individual
assets and to identify the associated risks objectively
Company may not be able to raise funds to
exploit its assets or continue as a going
concern
Company has given security over its assets
to its lender, LOG
• Management maintains regular dialogue with a variety of
potential funding partners.
• Management is in discussion with the Administrators of LOG
who have acknowledged the importance of developing the
Company’s assets in order to return value to LCAF bond
holders. The LOG shareholders have made public
announcements of their intention to continue to support the
Group and that the Group’s ongoing operations are not
adversely affected by the LOG Administration.
Operations
Operations may not go to plan, leading to damage, pollution, cost overruns and poor outcomes.
Risk
Mitigation
Individual wells may not deliver recoverable
oil and gas reserves
•
Operations may take far longer or cost more
than expected
Resource estimates may be misleading
curtailing actual reserves recovered
Thorough pre-drill evaluations are conducted to identify the
risk/reward balance
Exposure selectively mitigated through farm-out
•
• Management applies rigorous budget control
•
Adequate working capital is retained to cover reasonable
eventualities
•
The Group deploys qualified personnel
• Regular third-party reports are commissioned
•
A prudent range of possible outcomes are considered within
the planning process
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CORPORATE GOVERNANCE (CONT’D)
Corporate Governance Statement (continued)
Licensing & Regulation
The Group may be unable to meet its licence and regulatory obligations.
Risk
Mitigation
UKCS Licences may be revoked
• Continue thorough communications with the OGA to
determine licence status and meet requirements
Personnel
The Company relies upon a pool of experienced and motivated personnel to identify and execute successful investment
strategies
Risks
Mitigation
Key personnel may be lost to other
companies
Difficulty in attracting the necessary
into
talent as
development of its projects.
the Group moves
Commercial Environment
• The Remuneration Committee regularly evaluates
they remain
to ensure
incentivisation schemes
competitive
• The Group continues to review and adopt attractive
packages for both staff and contractors
World and regional markets continue to be volatile with fluctuations and infrastructure access issues that might hinder
the Company’s business success
Risk
Mitigation
Volatile commodity prices mean that the
Company cannot be certain of the future
sales value of its products
•
Price mitigation strategies may be employed at the point of
major capital commitment
• Gas may be sold under long-term contracts reducing
exposure to short term fluctuations
• Oil and gas price hedging contracts may be utilised where
Brexit
The Group may not be able to get access, at
reasonable cost,
infrastructure and
to
product markets when required
to support
field development
Credit
programmes may not be available at
reasonable cost
•
•
•
•
viable.
Budget planning considers a range of commodity pricing
The Group does not see Brexit having any significant impact
on its business model. The Company’s production will be
indigenous, and the UK gas market is not forecast to be
significantly directly impacted by an exit from the EU, being
a substantial core element of UK primary energy demand.
However, access to overseas personnel and equipment
may be affected to a greater or lesser extent, depending on
the precise Brexit outcome
A range of different off-take options are pursued wherever
possible
The Company seeks to build and maintain strong banking
relationships and initiates funding discussions at as early a
stage a practicable
Corporate Hedging Strategy and Implementation
The primary objective of the Company’s hedging policy is to protect projected future cash flows, generated from
operations, against unforeseen changes in short and medium-term market conditions.
No hedging instruments were utilised to date in view of the limited exposures carried out so far. As the Company’s
capital investment programmes increase, hedging will be carried out in a simple and cost-effective manner, retaining
exposure to upside but avoiding any speculative exposure to commodity prices or exchange rates. The application of
the policy is within a range to require exercise of management judgement in the light of market conditions and business
variables.
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CORPORATE GOVERNANCE (CONT’D)
Corporate Governance Statement (continued)
Insurance
The Group insures the risks it considers appropriate for the Group’s needs and circumstances. However, the Group
may elect not to have insurance for certain risks, due to the high premium costs associated with insuring those risks or
for various other reasons, including an assessment that the risks are remote.
Financial Controls
The Company has an established framework of internal financial controls, the effectiveness of which is regularly
reviewed by the Executive Management, the Audit Committee and the Board in light of an ongoing assessment of
significant risks facing the Company.
In 2018, the Board approved and adopted an updated Financial Operating Policy for the Group.
–
– The Financial Operating Policy is the framework to regulate the financial processes of the Group; from the
concept of Group strategy through to the payment of invoices. The key objectives of the Financial Operating
Policy are to: -
- provide a clear framework for internal financial control;
- define the levels of financial authority for Staff, Contractors, Directors and the Board;
and
- set out the processes for budgeting and financial reporting.
– The Board is responsible for reviewing and approving overall Company strategy, approving revenue and capital
budgets and plans, and for determining the financial structure of the Company including treasury and tax.
– The Audit Committee assists the Board in discharging its duties regarding the financial statements, accounting
policies and the maintenance of proper internal business and operational and financial controls, including the
review of results of work performed by the Group controls function.
– There are comprehensive procedures for budgeting and planning, for monitoring and reporting to the Board
business performance against those budgets and plans and for forecasting expected performance over the
remainder of the financial period. These cover profits, cash flows, capital expenditure and balance sheets.
– The Company has a consistent system of prior appraisal for investments, overseen by the Chief Financial
Officer and Chief Executive Officer, with defined financial controls and procedures with which each business
area is required to comply in order to be granted investment funds for development.
Non-financial Controls
The Board recognises that maintaining sound controls and discipline is critical to managing the downside risks to our
plan.
The Board has ultimate responsibility for the Group’s system of internal control and for reviewing its effectiveness.
However, any such system of internal control can provide only reasonable, but not absolute, assurance against material
misstatement or loss. The Board considers that the internal controls in place are appropriate for the size, complexity
and risk profile of the Group. The principal elements of the Group’s internal control system include:
– Close management of the day-to-day activities of the Group by the Executive Directors.
– An organisational structure with defined levels of responsibility, which promotes entrepreneurial decision-
making and rapid implementation while minimising risks.
– A comprehensive annual budgeting process.
– Detailed monthly reporting of performance against budget.
– Central control over key areas such as capital expenditure authorisation and banking facilities.
The Group continues to review its system of internal control to ensure compliance with best practice, while also having
regard to its size and the resources available. As part of the Group’s review a number of non-financial controls covering
areas such as regulatory compliance, business integrity, health and safety, risk management, business continuity and
corporate social responsibility have been assessed. The key elements of those non-financial controls are set out below.
Standards and Policies
The Board is committed to maintaining appropriate standards for all the Company’s business activities and ensuring
that these standards are set out in written policies and kept under review.
Approval Process
All material contracts are required to be reviewed and signed by a senior Director of the Company. Major contracts
require the signature of 2 directors.
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CORPORATE GOVERNANCE (CONT’D)
Corporate Governance Statement (continued)
Re-assessment
The Company has a Business Risk Register with business continuity plans to address key risks that have an immediate
impact. Risks facing the business are re-assessed and potential mitigating actions are considered and implemented to
help protect against those risks.
5. Maintaining the Board as a well-functioning, balanced team led by the Chair
The Board comprises the Non-Executive Chair, two Executive Directors and three Non-Executive Directors. On 1
January 2019 Fiona MacAulay became Chair succeeding Mark Routh, who stepped down on this date. On 1 March
2018, Andrew Hockey was appointed CEO. In April 2018 Mark Hughes, COO was appointed as a director of the
Company and its three subsidiaries.
On 9 January 2019 Fiona MacAulay became interim Chair of the Audit Committee, succeeding Martin Ruscoe, who
had held the role since February 2018. She continues as the Chair of the HSE and Technical subcommittee of the
Board.
The Board considers, after careful review, that its previous Non-Executive Directors brought an independent judgement
to bear. Fiona MacAulay had previously been appointed as the Company’s Senior Non-executive director on 10 July
2018 and qualifies as independent. The Company is currently recruiting one further Independent Directors. Both Charles
Hendry and Martin Ruscoe are considered non-independent since they are appointees from the Company’s major
investor London Oil and Gas Limited.
On 9 January 2019, Robin Storey was appointed as General Counsel and Company Secretary.
Non-executive directors are expected to devote such time as necessary for proper performance of their duties. This
includes regular attendance at Board, AGM, shareholder and committee meetings.
The Board is satisfied that it has a suitable balance between independence on the one hand and knowledge of the
Company on the other, to enable it to discharge its duties and responsibilities effectively.
All Directors are encouraged to use their independent judgement and to challenge all matters, whether strategic or
operational. During the year at least six scheduled Board meetings take place and a number of additional meetings as
may be required. These are held at IOG’s head office in London.
Key Board activities include:
– Considering our financial and non-financial policies.
– Discussing strategic priorities.
– Discussing the Group’s capital structure and financial strategy, including capital investments and shareholder
returns.
– Discussing internal governance processes.
Directors’ Conflict of Interest
The Company has effective procedures in place to monitor and deal with conflicts of interest. The Board is aware of
the other commitments and interests of its Directors and changes to these commitments and interests are reported to
and, where appropriate, agreed with the rest of the Board.
Directors’ Attendance:
Director
Andrew Hay
Andrew Hockey
Charles Hendry
Fiona MacAulay
Mark Hughes
Mark Routh
Martin Ruscoe
Audit Committee
Remuneration and
Nominations Committee
Board
2 (of 2)
17
17
9 (of 9)
11 (of 11)
17 Chair
n/a
n/a
6 (of 6)
2 (of 2)
n/a
n/a
17
6 (of 6) Acting Chair
n/a
n/a
1 (of 1)
1 (of 1)
n/a
1 (of 1) Chair
1 (of 1)
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CORPORATE GOVERNANCE (CONT’D)
Corporate Governance Statement (continued)
6. Ensure that between them the Directors have the necessary up-to-date experience, skills and
capabilities
The Board is satisfied that, between the Directors, it has an effective and appropriate balance of skills and experience,
including in the areas of technical Oil and Gas subsurface, project management, drilling and facilities experience and
in the areas of banking, financial and commercial skills and experience. All Directors receive regular and timely
information on the Group’s operational and financial performance. Relevant information is circulated to the Directors
by the Company Secretary in advance of meetings. The business reports monthly on its headline performance against
its agreed budget and the Board reviews the monthly update on performance and any significant variances are reviewed
at each meeting.
All Directors retire by rotation at regular intervals in accordance with the Company’s Articles of Association.
Appointment, removal and re-election of Directors
The Board makes decisions regarding the appointment and removal of Directors and there is a formal, rigorous and
transparent procedure for appointments. The Company’s Articles of Association require that one-third of the Directors
must stand for re-election by shareholders annually in rotation; that all Directors must stand for re-election at least once
every three years; and that any new Directors appointed during the year must stand for election at the AGM immediately
following their appointment.
The Board of directors has a mix of experience, skills and personal qualities that help deliver the strategy of the
Company. The Company will ensure that between them the directors have the necessary up-to-date experience, skills
and capabilities to deliver the Company strategy and targets. Each director is listed on the website and in the annual
report along with a clear description of their role and experience.
The Board also evaluates the balance of skills, knowledge and experience on the Board and considers all new Board
appointments and re-appointments against this evaluation.
Independent Advice
All Directors are able to take independent professional advice in the furtherance of their duties, if necessary, at the
Company’s expense. In addition, the Directors have direct access to the advice and services of the General Counsel
and Company Secretary, the Chief Executive Officer and the Chief Financial Officer.
Experience, Skills and Capabilities
Biographical details of the directors and their relevant experience can be found on the Company website at the following
link https://www.independentoilandgas.com/board.html.
7. Evaluate Board performance based on clear and relevant objectives, seeking continuous improvement.
The Chair will continue to informally assess the individual contributions of each of the members of the team to ensure
that Company strategy is effectively implemented, and that: -
-
-
-
Their contribution is relevant and effective.
That they are committed.
Where relevant, they have maintained their independence.
Over the next 12 months we intend to more formally review the performance of what is a new board team as a unit,
using external consultants where appropriate, to ensure that the members of the Board collectively function in an
efficient and productive manner.
8. Promote a culture that is based on ethical values and behaviours
The Board aims to lead by example and do what is in the best interests of the Company.
The Company operates a corporate culture that is based on ethical values and behaviours. It maintains policies and
processes that are appropriate to do this for a Company of its size. The Executive Directors communicate regularly with
staff through meetings and messages.
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CORPORATE GOVERNANCE (CONT’D)
Corporate Governance Statement (continued)
The Board has implemented a robust governance framework including a Code of Conduct, which includes the
Company’s Compliance with Anti-bribery and Corruption Policy that is incorporated into our Staff Hand Book and is
communicated to all employees. The Code provides clear guidance on how the members of staff are expected to
behave towards other colleagues, suppliers, customers, shareholders and on our wider responsibility to the
communities within which we operate. All employees are expected to comply with the Code and any violations of it
may be reported to local management or the Group HR.
Anti-bribery and Corruption Policy
Company policy is to conduct all its business in an honest and ethical manner. The Company and Group apply a zero-
tolerance approach to bribery and corruption and is committed to acting professionally, fairly and with integrity in all its
business dealings and relationships wherever it operates by implementing and enforcing effective systems to counter
bribery.
9. Maintain governance structures and processes that are fit for purpose and support good decision-
making by the Board
Board programme
The Board meets at least six times each year in accordance with its scheduled meeting calendar.
The Board sets direction for the Company through a formal schedule of matters reserved for its decision. Prior to the
start of each financial year, a schedule of dates for that year’s Board meetings is compiled to align as far as reasonably
practicable with the Company’s financial calendar while also ensuring an appropriate spread of meetings across the
financial year. This may be supplemented by additional meetings as and when required.
During 2018, the Board met for its twelve scheduled meetings and five further ad-hoc meetings. The Board and its
subcommittees receive appropriate and timely information prior to each meeting; a formal agenda is produced for each
meeting and Board and Committee papers are distributed several days before meetings take place. Any Director may
challenge Company proposals and decisions are taken democratically after discussion. Any Director who feels that
any concern remains unresolved after discussion may ask for that concern to be noted in the minutes of the meeting,
which are then circulated to all Directors by the Chairman. Any specific actions arising from such meetings are agreed
by the Board or relevant Committee and then followed up by the Company’s executive management.
Roles of the Board, Chair and Chief Executive Officer.
The Board is responsible for the long-term success of the Company. There is a formal schedule of matters reserved to
the Board. It is responsible for overall Group strategy; approval of major investments (whether Capex or Opex);
approval of the annual and interim results; annual budgets and Board structure. It monitors the exposure to key
business risks and reviews the strategic direction of all trading subsidiaries, their annual budgets and their performance
in relation to those budgets. There is a clear division of responsibility at the head of the Company. The Chair is
responsible for running the business of the Board and for ensuring appropriate strategic focus and direction. The Chief
Executive Officer is responsible for proposing the strategic focus to the Board, implementing it once it has been
approved and overseeing the management of the Company through the Executive Team.
All Directors receive regular and timely information on the Group’s operational and financial performance. Relevant
information is circulated to the Directors in advance of meetings. The business reports monthly on its headline
performance against its agreed budget and the Board reviews the monthly update on performance and any significant
variances are reviewed at each meeting. Senior executives below Board level attend Board meetings where appropriate
to present business updates. Board meetings throughout the year are held at the Company’s head office.
Executive Team
The Executive Team comprises Andrew Hockey the Chief Executive Officer, James Chance the Chief Financial Officer,
Mark Hughes the Chief Operating Officer, Rupert Newall, Head of Corporate Finance and Robin Storey, General
Counsel and Company Secretary. They are responsible for formulation of the proposed strategic focus for submission
to the Board, the day-to-day management of the Group’s businesses and its overall trading, operational and financial
performance in fulfilment of that strategy, as well as plans and budgets approved by the Board of Directors. The
Executive Team also manages and oversees key risks, management development and corporate responsibility
programmes. The Chief Executive Officer reports to the plc Board on issues, progress and recommendations for
change. The controls applied by the Executive Team to financial and non-financial matters are set out earlier in this
document and the effectiveness of these controls is regularly reported to the Audit Committee and the Board.
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CORPORATE GOVERNANCE (CONT’D)
Corporate Governance Statement (continued)
Board Committees
The Board is supported by the Audit Committee, Remuneration and Nomination Committee and the HSE and Technical
Committee. Each subcommittee has access to such resources, information and advice as it deems necessary, at the
cost of the Company, to enable the committee to discharge its duties. The terms of reference of each committee are
as follows: -
Audit Committee
The Audit Committee comprises Esa Ikaheimonen (Chair), Fiona MacAulay, Martin Ruscoe and Charles Hendry. The
Audit Committee has primary responsibility for monitoring the quality of internal controls and ensuring that the financial
performance of the Group is properly measured and reported on. In addition, it receives, and reviews reports from the
Company’s management and auditors. The Audit Committee meets at least twice a year and has unrestricted access
to the Company’s auditors.
Remuneration & Nominations Committee
The Remuneration Committee comprises Fiona MacAulay (Chair), Martin Ruscoe and Charles Hendry. The
Remuneration Committee determines the remuneration of the executive directors and grants share options and any
other equity incentives pursuant to any share option scheme or LTIP in operation from time to time. The Remuneration
Committee meets at least twice a year.
The Nomination Committee comprises Fiona MacAulay (Chair), Martin Ruscoe and Charles Hendry. The Committee
is chaired by the Chair unless the matter under discussion is their own succession. Other Directors are invited to attend
as appropriate and only if they do not have a conflict of interest. The Committee is also assisted by executive search
consultants as and when required. The Committee’s principal responsibility is to lead the process for Board
appointments and to make recommendations for maintaining an appropriate balance of skills on the Board.
HSE and Technical Committee
The HSE and Technical Committee comprises Fiona MacAulay (Chair), Andrew Hockey and Mark Hughes. The HSE
and Technical Committee determines the Company’s Environmental Management Policy, its Health and Safety
Management Policy and directs the overall governance of the Company’s Subsurface and Technical Management
policies.
BUILD TRUST
10. Communicate how the Company is governed and is performing by maintaining a dialogue with
shareholders and other relevant stakeholders
The Company communicates with shareholders through the Annual Report and Accounts, full-year and half-year interim
announcements, the Annual General Meeting (‘AGM’), General Meetings (‘GMs’) and one-to-one meetings with large
existing or potential new shareholders. Investor Relations are managed by the Executive Team and email queries from
private individual shareholders are handled with responses limited to clarifying information that is already in the public
domain.
In regard to a general meeting of the Company, once the meeting has concluded the results of the meeting are released
through a regulatory news service and a copy of the announcement is posted on the Company’s website. If it became
relevant an explanation of actions where a significant proportion of votes (e.g. 20% of votes received) is cast against a
resolution would be provided.
A range of corporate information (including all Company announcements, third party reports, summaries of key assets
and presentations) is also available to shareholders, investors and the public on the Company’s corporate website,
https://www.independentoilandgas.com.
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GLOSSARY of KEY TERMS
“1C”
“2C”
“3C”
‘‘3D-seismic’’
“1P”
“2P”
“3P”
‘‘API’’
‘‘appraisal well’’
‘‘barrels’’ or ‘‘bbls’’ or “Bbls”
‘‘BCF’’ or “BCF” or “Bscf”
‘‘Best Estimate’’
‘‘block’’
‘‘Boe’’ or “BOE”
‘‘Brent Crude’’
“Carboniferous”
‘‘Contingent Resources’’
‘‘Cretaceous’’
‘‘discovery’’
‘‘farm-in’’
‘‘farm-out’’
‘‘FDP’’
‘‘field’’
‘‘formation’’
‘‘ft’’
“G&A”
“GIIP”
‘‘gross resources’’
the minimum estimate of Contingent Resources;
the Best Estimate of Contingent Resources;
the maximum estimate of Contingent Resources;
geophysical data that depicts the subsurface strata in three dimensions. 3D-
seismic typically provides a more detailed and accurate interpretation of the
subsurface strata than 2D seismic;
the Proved Reserves;
the sum of Proved Reserves + Probable Reserves;
the sum of Proved Reserves + Probable plus Possible Reserves;
a standard measure of oil density, as defined by the American Petroleum
Institute;
a well drilled as part of an appraisal drilling programme which is carried out to
determine the physical extent, reserves and likely production rate of a field;
a unit of volume measurement used for petroleum and its products (for a typical
crude oil 7.3 barrels ≈ 1 tonne: 6.29 barrels ≈ 1 cubic metre);
billion (109) standard cubic feet; 1 BCF is approximately equal to 172,414 Boe
or 23,618 tonnes of oil equivalent, using a factor of 5.8 BCF per MMBbls;
the middle value in a range of estimates considered to be the most likely. If
based on a statistical distribution, can be the mean, median or mode depending
on usage;
an area subdivision of the UKCS of 10 minutes of latitude by 12 minutes of
longitude measuring approximately 10 by 20 kilometres, forming part of a
quadrant. Each quadrant is divided into a grid, five blocks wide and six blocks
deep, and numbered 1 to 30 from NW to SE e.g. Block 14/13 is the 13th block
in Quadrant 14;
barrels of oil equivalent. One barrel of oil is approximately the energy equivalent
of 5,800 cubic feet of natural gas;
an international benchmark comprising a mix of crude oil from 15 different oil
fields in the North Sea;
a geological period and system that extends from the end of the Devonian
Period, about 359 million years ago, to the beginning of the Permian Period,
about 299 million years ago;
those quantities of petroleum estimated, as of a given date, to be potentially
recoverable from known accumulations by application of development projects,
but which are not currently considered to be commercially recoverable due to
one or more contingencies;
geological strata formed during the period 140 million to 65 million years before
the present;
an exploration well which has encountered hydrocarbons for the first time in a
structure;
when a company acquires an interest in a block, by taking over all, or part of, the
financial commitment for drilling an exploration well;
to assign an interest in a licence to another party;
field development plan;
an area consisting of either a single reservoir or multiple reservoirs, all grouped
on or related to the same individual geological structural feature and/or
stratigraphic condition;
a layer or unit of rock. A productive formation in the context of reservoir rock;
foot/feet;
general and administrative;
gas initially in place;
the total estimated petroleum that is potentially recoverable from a field or
prospect;
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GLOSSARY of KEY TERMS (CONT’D)
‘‘hydrocarbon’’
‘‘km’’
‘‘km2’’ or “sq. km”
‘‘licence’’
‘‘Mcf’’ or “mcf”
“Mcfd” or “mcfd”
“MMbbl” or “MMBbls”
“MMBO”
“MMBOE”
“MMcf”
“MMcfd”
“MMscf”
“MMscfd”
“NUI”
‘‘oil’’
‘‘oil equivalent’’
‘‘operator’’
“P90”
“P50”
“P10”
‘‘petroleum’’
‘‘probable reserves’’
‘‘Promote Licence’’
‘‘prospect’’
‘‘prospective resources’’
a compound containing only the elements hydrogen and carbon. May exist as
a solid, a liquid or a gas. The term is mainly used in a catch-all sense for oil, gas
and condensate;
kilometre;
square kilometres;
an exclusive right to search for or to develop and produce hydrocarbons within
a specific area. Usually granted by the State authorities and may be time limited;
thousand standard cubic feet;
thousand cubic feet per day;
millions (106) of barrels of oil;
million (106) barrels of oil;
million (106) barrels of oil equivalent;
million (106) cubic feet;
million (106) cubic feet per day;
million (106) standard cubic feet;
million (106) standard cubic feet per day;
Normally Unmanned Installation;
mixture of liquid hydrocarbons of different molecular weights;
international standard for comparing the thermal energy of different fuels;
the company that has legal authority to drill wells and undertake production of
hydrocarbons found. The operator is often part of a consortium and acts on
behalf of such consortium;
in the probabilistic estimation of hydrocarbon reserves, a term referring to the
quantity of recoverable hydrocarbons from a reservoir having a 90 per cent.
probability of being produced. Often also referred to as Proved or 1P;
in the probabilistic estimation of hydrocarbon reserves, a term referring to the
quantity of recoverable hydrocarbons from a reservoir having a 50 per cent.
probability of being produced. Often also referred to as “Proved + Probable” or
2P;
in the probabilistic estimation of hydrocarbon reserves, a term referring to the
quantity of recoverable hydrocarbons from a reservoir having a 10 per cent.
probability of being produced. Often also referred to as “Proved + Probable +
Possible” or 3P;
a generic name for hydrocarbons, including crude oil, natural gas liquids, natural
gas and their products;
those unproved reserves which analysis of geological and engineering data
suggests are more likely than not to be recoverable. In this context, when
probabilistic methods are used, there should be at least a 50% probability that
the quantities actually recovered will equal or exceed the sum of estimated
Proved + Probable reserves;
a specific type of licence awarded by DECC whereby licence holders are given
two years after an award, with low rental payments and obligations, in order to
attract the technical, environmental and financial capacity to complete an agreed
work programme. The licence will expire after two years if the licensee has not
made a firm commitment to DECC to complete the work programme;
a project associated with a potential accumulation of oil or natural gas that is
sufficiently well defined to represent a viable drilling target;
those quantities of petroleum estimated, as of a given date, to be potentially
recoverable
future
development projects;
from undiscovered accumulations by application of
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GLOSSARY of KEY TERMS (CONT’D)
‘‘proven reserves’’
‘‘quadrant’’
‘‘recovery factor’’
‘‘reserves’’
‘‘reservoir’’
‘‘resources’’
“Rotliegendes” or
“Rotliegend”
“STOOIP” or “STOIIP”
‘‘scf’’
‘‘seismic survey’’
“TCF” or “tcf”
“UKCS”
those quantities of petroleum which, by analysis of geological and engineering
data, can be estimated with reasonable certainty to be commercially
recoverable, from a given date forward, from known reservoirs and under current
economic conditions, operating methods and government regulations. Proved
reserves can be categorised as developed or undeveloped. If deterministic
methods are used, the term reasonable certainty is intended to express a high
degree of confidence that the quantities will be recovered. If probabilistic
methods are used, there should be at least a 90% probability that the quantities
actually recovered will equal or exceed the estimate;
an area subdivision of the UKCS of 1 degree of longitude by 1 degree of latitude
- typically around 6,600km2. On the UKCS each quadrant is further subdivided
into 30 blocks;
the percentage of the hydrocarbon in place that can be produced;
those quantities of petroleum anticipated to be commercially recoverable by
application of development projects to known accumulations from a given date
forward under defined conditions. Reserves must further satisfy four criteria:
they must be discovered, recoverable, commercial and remaining (as of the
evaluation date) based on the development project(s) being applied;
a subsurface body of rock having sufficient porosity and permeability to store
and transmit fluids. A reservoir is a critical component of a complete petroleum
system;
deposits of naturally occurring hydrocarbons which, if recoverable, include those
volumes of hydrocarbons either yet to be found (prospective) or if found the
development of which depends upon a number of factors (technical, legal and/or
commercial) being resolved (contingent);
a lithostratigraphic geological unit of early Permian age (beneath the Zechstein
and above the Carboniferous) that is found in the subsurface of large areas in
western and central Europe;
stock tank oil originally in place or stock tank oil initially in place;
standard cubic feet;
a method by which an image of the earth’s subsurface is created through the
generation of shockwaves and analysis of their reflection from rock strata. Such
surveys can be done in two or three-dimensional form;
trillion (1012) standard cubic feet; 1 tcf is approximately equal to 172.4 MMBoe
or 23.6 million tonnes of oil equivalent, using a factor of 5.8 BCF per MMBbls;
United Kingdom Continental Shelf.
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REPORT OF THE DIRECTORS FOR THE YEAR ENDED 31 DECEMBER 2018
The directors present their report and audited financial statements of Independent Oil and Gas plc (“the Company”) and
its subsidiaries ("the Group") for the year ended 31 December 2018. All amounts are shown in Pounds Sterling, unless
otherwise stated.
The Company has its headquarters in London and its oil and gas interests are in the UK sector of the North Sea.
Information about the principal activities of the business, statement of reserves and resources, operational and financial
updates, the principal risks and uncertainties faced by the business, the Group’s KPIs and the Directors’ going concern
assessment can be found in the Strategic Report / Finance Review.
Dividend
The Directors do not recommend the payment of a dividend (2017: £nil).
Political contributions
No payments to political parties have been made during the year (2017: nil).
Future Developments
Following the arrangement of debt funding in late 2015 and early 2016 and further debt funding in both February and
September 2018, the Group plans to appraise and develop its existing discoveries, explore its new licence interests
and seek new investment opportunities. Full details are included in the Strategic Report.
Directors and their Interests
The directors who held office during the year, and at the date of this report, were: -
Mark Routh (resigned 31 December 2018)
Martin Ruscoe
Andrew Hay (resigned 13 February 2018)
Andrew Hockey
Rt. Hon. Charles Hendry
Mark Hughes (appointed 18 April 2018)
Fiona MacAulay (appointed 10 July 2018, appointed Chair on 1 January 2019)
Esa Ikaheimonen (appointed 14 March 2019)
Directors’ biographies and committee memberships are set out in the Corporate Governance section from pages 23 to
34.
The Group has provided the directors with third party indemnity insurance of £25 million for 2018/19 (2017/18 - £25
million)
Directors who held office at the end of the financial year had the following interests in shares of the Company:
Ordinary shares of 1p each At 31 December 2018
178,000
Mark Hughes
144,813
Martin Ruscoe
At 31 December 2017
0
144,813
Details of directors’ emoluments and share options are set out in Note 4 to the financial statements.
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REPORT OF THE DIRECTORS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
Substantial Shareholdings
Except for the holdings of ordinary shares listed below, the Company has not been notified by or become aware of any
persons holding 3% or more of the 126,868,156 issued ordinary shares of 1p each of the Company at 4 April 2019.
Shareholder
Hargreaves Lansdown (Nominees)
Limited
Interactive Investor Services Nominees
Limited
Aurora Nominees Limited
Hargreaves Lansdown (Nominees)
Limited <15942>
Hargreaves Lansdown (Nominees)
Limited
Barclays Direct Investing Nominees
Limited
Remainder
TOTAL
Number
16,075,605
13,118,996
9,593,417
9,260,506
7,658,266
5,431,092
66,343,130
127,481,012
%
12.61
10.29
7.53
7.26
6.01
4.26
52.04
100%
Risk Management
Information on the financial and operational risks faced by the Group and the risk management objectives and policies
is included in the Strategic Report,
Financial Instruments
Information on financial instruments can be found in Note 20 to the financial statements.
Related Parties
Information on related party transactions can be found in Note 22 to the financial statements.
Subsequent Events
Information on subsequent events can be found in Note 24 to the financial statements.
Shareholder Communications
The Company has a website, www.independentoilandgas.com, to provide information to shareholders.
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INDEPENDENT AUDITOR’S REPORT TO THE MEMBERS OF INDEPENDENT OIL AND GAS PLC
Independent auditor’s report to the members of Independent Oil & Gas Plc
Opinion
We have audited the financial statements of Independent Oil and Gas Plc (the ‘Parent Company’) and its subsidiaries
(the ‘Group’) for the year ended 31 December 2018 which comprise the consolidated statement of comprehensive
income, the consolidated and company statements of changes in equity, the consolidated statement of financial
position, the company statement of financial position, the consolidated cash flow statement, the company cash flow
statement and notes to the financial statements, including a summary of significant accounting policies and notes to the
financial statements, including a summary of significant accounting policies.
The financial reporting framework that has been applied in the preparation of the financial statements is applicable law
and International Financial Reporting Standards (IFRSs) as adopted by the European Union and as regards the Parent
Company financial statements, as applied in accordance with the provisions of the Companies Act 2006.
In our opinion:
•
•
•
•
the financial statements give a true and fair view of the state of the Group and of the Parent Company’s affairs as
at 31 December 2018 and of the Group’s loss for the year then ended;
the Group financial statements have been properly prepared in accordance with IFRSs as adopted by the European
Union;
the Parent Company financial statements have been properly prepared in accordance with IFRS as adopted by the
European Union and as applied in accordance with the provisions of the Companies Act 2006; and
the financial statements have been prepared in accordance with the requirements of the Companies Act 2006.
Basis for opinion
We conducted our audit in accordance with International Standards on Auditing (UK) (ISAs (UK)) and applicable law.
Our responsibilities under those standards are further described in the Auditor’s responsibilities for the audit of the
financial statements section of our report. We are independent of the Group and the Parent Company in accordance
with the ethical requirements that are relevant to our audit of the financial statements in the UK, including the FRC’s
Ethical Standard as applied to listed entities, and we have fulfilled our other ethical responsibilities in accordance with
these requirements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a
basis for our opinion.
Material uncertainty related to going concern
We draw attention to Note 1 of the financial statements concerning the Group and the Parent Company’s ability to
continue as a going concern. The matters explained in Note 1 relating to the uncertainty around the Group and Parent
Company’s ability to fund its working capital needs, development plans and loan repayments indicate the existence of
a material uncertainty which may cast significant doubt over the Group and Parent Company’s ability to continue as a
going concern. Our opinion is not modified in respect of this matter.
We have highlighted going concern as a key audit matter based on our assessment of the significance of the risk and
the effect on our audit strategy.
Our audit procedures in response to this key audit matter included:
•
•
•
Analysing Management’s and the Directors’ cashflow forecast which forms the basis of their assessment that
the going concern basis of preparation remains appropriate for the preparation of the Group and Company
financial statements for a period of at least twelve months from the date of approval of these financial statements
Assessing and sensitising key costs included within the cashflow forecast and where available agreeing these
costs to other evidence obtained during the course of our audit work
Testing the mathematical integrity of the cashflow model in order to ensure the basis of preparation of the model
is in line with our expectations
• Obtaining and reviewing documents which support the funding streams included by Management and the
Directors in the Group cashflow forecast and confirming the documents to third party documents and public
available information
• Obtaining and reviewing correspondence in respect of the terms of the Group’s and Company’s debt facilities
and making an assessment of the ongoing availability of such funding
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INDEPENDENT AUDITOR’S REPORT TO THE MEMBERS OF INDEPENDENT OIL AND GAS PLC (CONT’D)
• Discussing with Management and the Board the Group’s strategy to continue to ensure funds are available to
the Group to fund its operations and development plans. Confirming statements made to publicly available
information and third-party documentation where available
• Reviewing and considering the adequacy of the disclosure within the financial statements relating to the
Directors’ assessment of the going concern basis of preparation.
Key audit matters
Key audit matters are those matters that, in our professional judgment, were of most significance in our audit of the
financial statements of the current period and include the most significant assessed risks of material misstatement
(whether or not due to fraud) we identified, including those which had the greatest effect on the overall audit strategy,
the allocation of resources in the audit and directing the efforts of the engagement team. These matters were addressed
in the context of our audit of the financial statements as a whole, and in forming our opinion thereon, and we do not
provide a separate opinion on these matters.
Carrying value of non-current assets
The Group’s non-current assets represent its most significant assets on the consolidated statement of financial
position as at 31 December 2018, comprising of capitalised evaluation & exploration (E&E) and development &
production (D&P) expenditure on its Southern North Sea Projects. Please refer to notes 8 and 9.
For both the E&E and D&P assets at each year end Management and the Board are required to assess whether
there are any potential impairment triggers which would indicate that the carrying value of a cash generating unit
(CGU) may not be recoverable. Given the materiality of the assets in the context of the Group’s consolidated
statement of financial position and the judgement involved in making this assessment we consider this to be a key
audit matter.
Management and the Board concluded that there were no impairment triggers present for any of the CGUs.
How we addressed the key audit matter in our audit
Our specific audit testing in this regard included:
• Holding meetings with operational management in order to be able to assess the operating activity
and development of the assets undertaken in the year
• Undertaking a review assessment against the accounting standard requirements of Management’s
and the Board’s conclusion around the number of CGUs identified
• Undertaking a review of licence concession agreements and supporting documentation in order to
assess compliance with key terms
• Reviewing Management’s impairment indicators assessment for each CGU against the criteria in
the accounting standards in order to determine whether their assessment was complete and in
accordance with the requirements of the accounting standard
Performing an independent assessment of financial and non-financial data for potential
impairment indicators, and
•
• Reviewing the competent persons reports, as applicable and field development plans, where
available for CGUs. In addition, we reviewed key model inputs to data obtained elsewhere during
the course of the audit, third party public available information and benchmark data in order to
assess whether there are any assumptions in the model which would suggest a potential
impairment indicator. Our work was undertaken in order to assess whether there were any
potential impairment triggers highlighted in the model which had not previously been identified.
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INDEPENDENT AUDITOR’S REPORT TO THE MEMBERS OF INDEPENDENT OIL AND GAS PLC (CONT’D)
Our application of materiality
Group materiality FY 2018
Group materiality FY 2017
Basis for materiality
£550,000
£330,000
1.4% of total assets
(2017: 1.5% of total assets)
Total Assets was determined as an appropriate basis as the principal focus of the Group remains fundamentally
focussed on the development of its oil and gas assets.
Materiality for the Parent Company was set at £410,000 (2017: £247,500) and was restricted to 75% of Group materiality
(2017: 75% of Group materiality).
We apply the concept of materiality both in planning and performing our audit and in evaluating the effect of
misstatements. We consider materiality to be the magnitude by which misstatements, including omissions, could
influence the economic decisions of reasonable users that are taken on the basis of the financial statements.
Importantly, misstatements below these levels will not necessarily be evaluated as immaterial as we also take account
of the nature of identified misstatements, and the particular circumstances of their occurrence, when evaluating their
effect on the financial statements as a whole.
Performance materiality is the application of materiality at the individual account or balance level set at an amount to
reduce to an appropriately low level the probability that the aggregate of uncorrected and undetected misstatements
exceeds materiality for the financial statements as a whole. Performance materiality was set at 75% (2017: 75%) of the
above materiality levels for both Group and Company.
We agreed with the Audit Committee that we would report to the Committee all individual audit differences identified
during the course of our audit in excess of £10,000.
Whilst materiality for the financial statements as a whole was £550,000 each significant component of the Group was
audited to a lower level of materiality ranging from £113,000 to £410,000 which was used to determine the financial
statement areas that were included within the scope of the Component audits and the extent of sample sizes used
during the audit.
An overview of the scope of our audit
Our Group audit scope focused on the Group’s principal activities and the reporting entities in which these operations
were held. As a result, we determined that there were three significant components, and all of these were subject to a
full scope audit. Together with the parent company and its Group consolidation, which were both also subject to a full
scope audit, these represent the significant components of the Group.
The remaining components of the Group were considered non-significant and these components were principally
subject to analytical review procedures, together with additional substantive testing over the risk areas detailed above
where applicable to that component.
The audits of each of the components were performed in the UK. All of the audits were conducted by BDO LLP.
Other information
The Directors are responsible for the other information. The other information comprises the information included in the
annual report other than the financial statements and our auditor’s report thereon. Our opinion on the financial
statements does not cover the other information and, except to the extent otherwise explicitly stated in our report, we
do not express any form of assurance conclusion thereon.
____________________________________________________________________________________________________________________
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INDEPENDENT AUDITOR’S REPORT TO THE MEMBERS OF INDEPENDENT OIL AND GAS PLC (CONT’D)
Other information (continued)
In connection with our audit of the financial statements, our responsibility is to read the other information and, in doing
so, consider whether the other information is materially inconsistent with the financial statements or our knowledge
obtained in the audit or otherwise appears to be materially misstated. If we identify such material inconsistencies or
apparent material misstatements, we are required to determine whether there is a material misstatement in the financial
statements or a material misstatement of the other information. If, based on the work we have performed, we conclude
that there is a material misstatement of this other information, we are required to report that fact. We have nothing to
report in this regard.
Opinions on other matters prescribed by the Companies Act 2006
In our opinion, based on the work undertaken in the course of the audit:
•
•
the information given in the Strategic Report and the Directors’ report for the financial year for which the financial
statements are prepared is consistent with the financial statements; and
the Strategic Report and the Directors’ report have been prepared in accordance with applicable legal
requirements.
Matters on which we are required to report by exception
In the light of the knowledge and understanding of the Group and the Parent Company and its environment obtained in
the course of the audit, we have not identified material misstatements in the strategic report or the Directors’ report.
We have nothing to report in respect of the following matters in relation to which the Companies Act 2006 requires us
to report to you if, in our opinion:
•
•
•
•
adequate accounting records have not been kept by the Parent Company, or returns adequate for our audit
have not been received from branches not visited by us; or
the Parent Company financial statements are not in agreement with the accounting records and returns; or
certain disclosures of Directors’ remuneration specified by law are not made; or
we have not received all the information and explanations we require for our audit.
Responsibilities of Directors
As explained more fully in the Directors’ responsibilities statement the Directors are responsible for the preparation of
the financial statements and for being satisfied that they give a true and fair view, and for such internal control as the
Directors determine is necessary to enable the preparation of financial statements that are free from material
misstatement, whether due to fraud or error.
In preparing the financial statements, the Directors are responsible for assessing the Group’s and the Parent Company’s
ability to continue as a going concern, disclosing, as applicable, matters related to going concern and using the going
concern basis of accounting unless the Directors either intend to liquidate the Group or the Parent Company or to cease
operations, or have no realistic alternative but to do so.
Auditor’s responsibilities for the audit of the financial statements
Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are free from
material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion.
Reasonable assurance is a high level of assurance; however, is not a guarantee that an audit conducted in accordance
with ISAs (UK) will always detect a material misstatement when it exists.
Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could
reasonably be expected to influence the economic decisions of users taken on the basis of these financial statements.
A further description of our responsibilities for the audit of the financial statements is located on the Financial Reporting
Council’s website: www.frc.org.uk/auditorsresponsibilities. This description forms part of our auditor’s report.
____________________________________________________________________________________________________________________
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INDEPENDENT AUDITOR'S REPORT TO THE MEMBERS OF INDEPENDENT OIL AND GAS PLC
Use of our report
This report is made solely to the Parent Company's members, as a body, in accordance with Chapter 3 of part 16 of
the Companies Act 2006. Our audit work has been undertaken so that we might state to the Parent Company's
members those matters we are required to state to them in an auditor's report and for no other purpose. To the fullest
extent permitted by law, we do not accept or assume responsibility to anyone other than the Parent Company and the
Parent Company's members as a body, for our audit work, for this report, or for the opinions we have formed.
8oo I,t€
Anne Sayerc (Senior Statutory Auditor)
For and on behalf of BDO LLP, Statutory Auditor
London
4 April 2019
BDO LLP is a limited liability partnership registered in England and Wales (with registered number OC3O512Z).
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CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME FOR THE YEAR ENDED 31 DECEMBER 2018
Consolidated Statement of Comprehensive Income
Notes
Administration expenses
Impairment of oil and gas properties
Project, pre-licence and exploration expenses
Net loss on settlement of liabilities
Foreign exchange (loss)/gain
Operating loss
Finance expense
Loss for the year before taxation
Taxation
Loss and total comprehensive loss for the year attributable to
equity holders of the parent
Loss for the year per ordinary share – basic
Loss for the year per ordinary share – diluted
The loss for the year arose from continuing operations.
The Notes on pages 52 to 89 form part of these financial statements.
8
3
3
5
6
7
7
7
2018
£000
(974)
(184)
(922)
(106)
(334)
2017
£000
(700)
(119)
(430)
(1)
333
_________
_________
(2,520)
(917)
(3,124)
_________
(1,834)
_________
(5,644)
(2,751)
-
_________
-
_________
(5,644)
(2,751)
_________
_________
4.6p
4.6p
2.5p
2.5p
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CONSOLIDATED AND COMPANY STATEMENTS OF CHANGES IN EQUITY FOR THE YEAR ENDED 31 DECEMBER 2018
Consolidated and Company Statements of Changes in Equity
Group:
At 1 January 2017
Loss for the year
Total comprehensive loss attributable to owners
of the parent
Settle creditors via issue of shares
Lapse of warrants
Issue of share options
Exercise of share options
At 31 December 2017
Loss for the year
Total comprehensive loss attributable to owners
of the parent
Issue of warrants
Issue of share options
Exercise of share options
At 31 December 2018
Company:
At 1 January 2017
Profit for the year
Total comprehensive income attributable to
owners of the parent
Settle creditors via issue of shares
Lapse of warrants
Issue of share options
Exercise of share options
At 31 December 2017
Loss for the year
Share
capital
Share
premium
£000
£000
1,093
-
20,460
-
_____ ________
-
105
-
-
5
-
1,877
-
-
-
_____ ________
22,337
1,203
Share-based
payment
reserve
£000
Accumulated
losses
Total equity
£000
£000
2,885
-
________
-
-
(10)
298
(74)
________
3,099
(28,738)
(2,751)
________
(2,751)
-
10
-
74
________
(31,405)
(4,300)
(2,751)
_______
(2,751)
1,982
-
298
5
_______
(4,766)
-
-
_____ ________
-
________
(5,644)
________
(5,644)
_______
-
-
-
-
-
-
-
66
______
_____
1,269
22,337
_____ ________
1,093
-
20,460
-
_____ ________
-
105
-
-
5
-
1,877
-
-
-
_____ ________
22,337
1,203
-
4,190
378
(1,359)
________
6,308
_______
2,885
-
________
-
-
(10)
298
(74)
________
3,099
(5,644)
-
-
1,359
________
(35,690)
________
(5,172)
1,176
________
1,176
-
10
-
74
________
(3,912)
(5,644)
4,190
378
66
_______
(5,776)
_______
19,266
1,176
_______
1,176
1,982
-
298
5
_______
22,727
-
-
_____ ________
-
________
(2,604)
________
(2,604)
_______
Total comprehensive loss attributable to owners
of the parent
Issue of warrants
Issue of share options
Exercise of share options
At 31 December 2018
-
-
-
66
-
-
-
-
_____ ________
22,337
1,269
______ ________
-
4,190
378
(1,359)
_______
6,308
_______
(2,604)
-
-
1,359
_______
(5,157)
________
(2,604)
4,190
378
66
_______
24,757
_______
Share capital - Amounts subscribed for share capital at nominal value.
Share premium - Amounts received on the issue of shares, in excess of the nominal value of the shares.
Share-based payment reserve - Amounts reflecting fair value of options and warrants issued.
Accumulated losses - Cumulative net losses recognised in the Statement of Comprehensive Income net of amounts recognised directly in equity.
The Notes on pages 52 to 89 form part of these financial statements.
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CONSOLIDATED CASH FLOW STATEMENT FOR THE YEAR ENDED 31 DECEMBER 2018
Consolidated Cash Flow Statement
Loss for the year
Depreciation, depletion and amortisation
Exploration asset write off
Loss on settlement of liabilities
Share based payments
Movement in trade and other receivables
Movement in trade and other payables
Interest received
Finance fees
Foreign exchange differences
Notes
2018
£000
2017
£000
7
8
3
(5,644)
(2,751)
9
184
106
187
(812)
(415)
(2)
3,206
142
_________
3
119
1
174
(278)
178
-
1,834
(333)
_________
Net cash used in operating activities
(3,039)
(1,053)
Investing activities
Purchase of intangible and tangible assets
Interest received
Acquisitions
Initial Thames Pipeline decommissioning security
Net cash used in investing activities
Financing activities
Proceeds from issue of equity instruments of the Group
Cash received from loans
Amounts repaid on loans
Finance fees paid
Net cash generated from financing activities
Net increase / (decrease) in cash and cash equivalents
Cash and cash equivalents at the beginning of the year
10
23
23
(14,327)
2
-
(500)
_________
(2,648)
-
(750)
-
_________
(14,825)
(3,398)
67
18,787
-
(433)
_________
8
6,372
(2,019)
(12)
_________
18,421
557
4,349
(102)
145
_________
247
_________
Cash and cash equivalents at end of year
17
702
_________
145
_________
The Notes on pages 52 to 89 form part of these financial statements.
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COMPANY CASH FLOW STATEMENT FOR THE YEAR ENDED 31 DECEMBER 2018
Company Cash Flow Statement
(Loss)/profit for the year
Depreciation charges
Investment write back
Loss on settlement of liabilities
Share based payments
Movement in trade and other receivables
Movement in trade and other payables
Inter-company service charge uplift
Interest received
Finance fees
Foreign exchange differences
Net cash used in operating activities
Investing activities
Purchase of intangible and tangible assets
Loans to subsidiary undertakings
Interest received
Investments in subsidiary undertakings
Net cash used in investing activities
Financing activities
Proceeds from issue of equity instruments of the Company
Cash received from loans
Amounts repaid on loans
Finance fees paid
Net cash generated from financing activities
Net (decrease) / increase in cash and cash equivalents
Cash and cash equivalents at the beginning of the year
Notes
2018
£000
2017
£000
18
11
3
10
23
23
(2,604)
1,176
8
-
106
138
(312)
(415)
(206)
(2)
1,322
142
_________
3
(1,870)
1
96
(284)
214
(105)
-
166
(200)
_________
(1,823)
(803)
(573)
(15,470)
2
-
_________
(371)
(2,539)
-
(750)
_________
(16,041)
(3,660)
67
18,787
-
(433)
_________
8
6,372
(2,019)
-
_________
18,421
557
4,361
(102)
145
_________
247
_________
Cash and cash equivalents at end of year
17
702
_________
145
_________
The Notes on pages 52 to 89 form part of these financial statements.
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018
1 Accounting policies
General information
Independent Oil and Gas plc is a public limited company incorporated and domiciled in England and Wales. The
Group’s and Company’s financial statements for the year ended 31 December 2018 were authorised for issue by the
Board of Directors on 28 March 2019 and the balance sheets were signed on the Board’s behalf by the CEO, Andrew
Hockey.
Basis of preparation and accounting
The principal accounting policies adopted in the preparation of the financial statements are set out below. The policies
have been consistently applied to all years presented, unless otherwise stated. The consolidated financial statements
are presented in GBP Sterling, which is also the functional currency of the Company and its subsidiaries. Amounts are
rounded to the nearest thousand, unless otherwise stated.
These financial statements have been prepared in accordance with International Financial Reporting Standards
adopted by the European Union, International Accounting Standards and Interpretations (collectively ‘IFRSs’) and with
those parts of Companies Act 2006 applicable to companies preparing their accounts under IFRS.
The preparation of financial statements in compliance with adopted IFRSs requires the use of certain critical accounting
estimates. It also requires Group management to exercise judgment in applying the Group's accounting policies. The
areas where significant judgments and estimates have been made in preparing the financial statements and their effect
are disclosed within this Note 1 on pages 62 and 63.
The consolidated financial statements have been prepared on a historical cost basis.
Going concern
The Board has reviewed the Group’s cash flow forecasts up until September 2020 having regard to its current financial
position and operational objectives. On 1 April 2019 the Group announced it had raised £16.6m (gross) of equity via
the placing of 165,795,050 shares for 10p per ordinary share and had simultaneously renegotiated the term of £7.1m
of LOG debt whereby repayments previously scheduled for 2019, which are now rescheduled to 1 January 2020 at the
earliest. The Group have continued to draw down against the LOG £15m facility having taken a further drawdown of
£3.925 million in January 2019. The Group have received confirmation from the LOG Administrators that the remaining
£3.925 million available to the Group under the £15m LOG facility will remain available to the Group under the original
terms of the facility, and as publicly noted by the LOG Administrators, they will continue to support the Group in its
endeavours to develop its dual Hub Strategy in order to generate shareholder return.
Notwithstanding this announcement the Group’s cashflow forecast to September 2020 indicates that the Group will
need additional funding to enable it to progress with its planned development activities and to meet its liabilities (working
capital and LOG scheduled debt repayments) as they fall due in the period from 1 January 2020. The Board; however,
is satisfied that the Group and Company will have sufficient financial resources available to meet its commitments based
on the likelihood of the Group being able to secure additional funding from existing stakeholders, the farmout of existing
assets and/or funding from new investors. The Consolidated Statement of Financial Position at 31 December 2018
details a net liability position of the Group of £5.8 million; however, the funding and LOG restructuring, pursuant to the
announcement on 1 April 2019, will both provide increased equity and the reduction of debt on the balance sheet,
Management identify this trend as an important steer to deliver its dual Hub Strategy and the development of its
associated oil and gas asset portfolio. Accordingly, the Board continue to adopt the going concern basis for the
preparation of these financial statements.
However, at the date of approval of these financial statements there are no legally binding agreements in place relating
to future fundraising. Therefore, there can be no certainty that additional funds will be forthcoming which indicates the
existence of a material uncertainty which may cast significant doubt about the Group and Company’s ability to continue
as a going concern and therefore it may be unable to realise its assets and discharge its liabilities in the normal course
of business. The financial statements do not include the adjustments that would result if the Group and Company was
unable to continue as a going concern.
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
1 Accounting policies (continued)
New and revised accounting standards
(i) New and amended standards adopted by the Group:
The accounting policies adopted are consistent with those of the previous financial year. New or amended financial
standards or interpretations adopted during the year and that have a significant impact upon the financial statements
are detailed below.
(ii) The following standards, amendments and interpretations, which are effective for reporting periods beginning after
the date of these financial statements, have not been adopted early: -
Standard
IFRS 16
IFRIC 23
IFRS 9
IAS 28
IFRS 3, IFRS 11, IAS 12, IAS 23
IAS 19
IFRS 3
IAS1, IAS8
n/a
IFRS 17
Description
Leases
Uncertainty over Income Tax Treatments
Prepayment Features with Negative
Compensation (Amendments)
Long-term Interest in Associates and Joint
Ventures (Amendments)
Annual Improvements to IFRS Standards 2015-
2017 Cycle
Plan Amendment, Curtailment or Settlement
(Amendments)
Definition of a Business (Amendments to IFRS 3)
Definition of Material (amendments to IAS1 and
IAS 8)
Amendments to References to the Conceptual
Framework in IFRS Standards
Insurance Contracts
Effective date
1 January 2019
1 January 2019
1 January 2019
1 January 2019
1 January 2019
1 January 2019
1 January 2020
1 January 2020
1 January 2020
1 January 2021
IFRS 16 “Leases” - the Board assesses that the net impact to the Income Statement in 2019 and future years will be
dependent on those prevailing lease contracts and other such similar oil and gas development contractual agreements
which may have been executed prior to 31 December 2019. The Board is uncertain as to the length of time such
contracts may cover; however, if such contracts cover any continuous period of greater than one year, then such
contracts will be subject to IFRS16. Such contracts will result in both assets and liabilities on the Balance Sheet to
increase by corresponding amounts, which, as at 31 December 2018 would have been immaterial. At 31 December
2018 the Group was not subject to any long-term lease contracts, other than for the rental of its office premises at 10
Arthur Street, London EC4R 9AY and the Crown Estate lease where the Thames Pipeline crosses the foreshore at
Bacton. The Company has not adopted this standard early and has not made any IFRS16 provision, for its office lease
or Crown Estate agreements, or otherwise, in the financial statements for the year ending 31 December 2018.
The application of the other standards above in future financial statements is not expected to have a material impact
on those financial statements.
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
1 Accounting policies (continued)
New significant standards and amendments effective 1 January 2018
IFRS 9 Financial Instruments
IFRS 9, Financial Instruments introduced new requirements for the recognition, classification and measurement of
financial assets and liabilities, derecognition of financial instruments, impairment of financial assets and hedge
accounting. IFRS 9 replaced the multiple classification and measurement models for financial assets and financial
liabilities that existed under IAS 39 Financial Instruments, and the basis on which financial assets are measured will
determine their classification as either, at amortised cost, fair value through profit and loss, or fair value through other
comprehensive income. The Group’s principal financial assets comprise cash and other receivables. All these financial
assets continue to be classified and measured at amortised cost. The Group’s principal financial liabilities comprise
trade and other payables and loans. All these financial liabilities continue to be classified and measured at amortised
cost.
The adoption of IFRS 9 has changed the Group’s accounting for impairment losses for financial assets by replacing
IAS 39’s incurred loss approach with a forward-looking expected credit loss approach. IFRS 9 requires the Group to
measure and recognise expected credit losses on all applicable financial assets.
The Company did not choose to adopt IFRS 9 early and have chosen not to apply the standard retrospectively on the
basis of the impact not being significant in terms of impairment and or additional expected credit losses (‘ECL’s)
recognised with regard to intercompany balances. The Company has assessed the resulting impact on the financial
statements and there was no material quantitative impact on the financial statements. There are a number of additional
disclosures that have been added to the financial statements.
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
1 Accounting policies (continued)
Basis of consolidation
Where the Company has control over an investee, it is classified as a subsidiary. The Company controls an investee if
all three of the following elements are present: power over the investee, exposure to variable returns from the investee,
and the ability of the investor to use its power to affect those variable returns. Control is reassessed whenever facts
and circumstances indicate that there may be a change in any of these elements of control.
The consolidated financial statements present the results of the Company and its subsidiaries as if they formed a single
entity. Inter-company transactions and balances between Group companies are therefore eliminated in full. The
financial statements of subsidiaries are included in the Group's financial statements from the date that control
commences until the date that control ceases.
Asset Acquisition
In the event of an asset acquisition, the cost of the acquisition is assigned to the individual assets and liabilities based
on their relative fair values. All directly attributable costs are capitalised. Contingent consideration is accrued for when
these amounts are considered probable and are discounted to present value based on the expected timing of payment.
Oil and gas exploration, development and producing assets
The Group adopts the following accounting policies for oil and gas asset expenditure, based on the stage of
development of the assets:
1) Pre-Licence
Expenditure incurred prior to the acquisition and/or award of a licence interest is expensed to the Statement of
Comprehensive Income as ‘Exploration Expenses’.
2) Exploration and evaluation (‘E&E’)
Capitalisation
Costs incurred after rights to explore have been obtained, such as geological and geophysical surveys, drilling and
commercial appraisal costs, and other directly attributable costs of exploration and appraisal including technical and
administrative overheads, are capitalised as intangible exploration and evaluation (‘E&E’) assets. The assessment of
what constitutes an individual E&E asset is based on technical criteria but essentially either a single licence area or
contiguous licence areas with consistent geological features are designated as individual E&E assets. Costs relating
to the exploration and evaluation of oil and gas interests are carried forward until the existence, or otherwise, of
commercial reserves have been determined.
E&E costs are not amortised prior to the conclusion of appraisal activities. Once active exploration is completed the
asset is assessed for impairment. If commercial reserves are discovered then the carrying value of the E&E asset is
reclassified as a development and production (‘D&P’) asset, within property, plant and equipment (‘PPE’), following
development sanction by the Board, but only after the carrying value is assessed for impairment at point of transfer and,
where appropriate, its carrying value adjusted. Following development sanction by the Board, a Field Development
Plan (‘FDP’) may be submitted. If it is subsequently assessed that commercial reserves have not been discovered, the
E&E asset is written off to the Statement of Comprehensive Income. The Group’s definition of commercial reserves for
such purpose is proven and probable (‘2P’) reserves on an entitlement basis.
Intangible E&E assets that relate to E&E activities that are not yet determined to have resulted in the discovery of
commercial reserves remain capitalised as intangible E&E assets at cost, subject to impairment assessments as set
out below.
Impairment
The Group’s oil and gas assets are analysed into cash generating units (‘CGU’) for impairment reporting purposes, with
E&E asset impairment testing being performed at an individual asset level. E&E assets are reviewed for impairment
when circumstances arise which indicate that the carrying value of an E&E asset exceeds the recoverable amount.
Such indicators would include but not limited to:
(i) adequate and sufficient data exists that render the resource uneconomic and unlikely to be developed;
(ii) title to the asset is compromised;
(iii) budgeted or planned expenditure is not expected in the foreseeable future; and
(iv) insufficient discovery of commercially viable resources leading to the discontinuation of activities.
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
1 Accounting policies (continued)
Oil and gas exploration, development and producing assets (continued)
The recoverable amount of the individual asset is determined as the higher of its fair value less costs to sell and value
in use. Impairment losses resulting from an impairment review are separately recognised and written off to the
Statement of Comprehensive Income.
Impaired assets are reviewed annually to determine whether any substantial change to their fair value amounts
previously impaired would require reversal.
A previously recognised impairment loss is reversed if the recoverable amount increases because of a change in the
estimates used to determine the recoverable amount, but not to an amount higher than the carrying amount that would
have been determined (net of depletion or amortisation) had no impairment loss been recognised in prior periods.
Reversal of impairments and impairment charges are credited/(charged) to a separate line item within the Statement of
Comprehensive Income.
3) Development and production (‘D&P’)
Capitalisation
Costs of bringing a field into production, including the cost of facilities, wells and sub-sea equipment together with E&E
assets reclassified in accordance with the above policy, are capitalised as a D&P asset within PPE. Normally each
individual field development will form an individual D&P asset but there may be cases, such as phased developments,
or multiple fields around a single production facility when fields are grouped together to form a single D&P asset. The
cost of development and production assets also include the cost of acquisitions and purchases of such assets, directly
attributable overheads, applicable borrowing costs and the cost of recognising provisions for future consideration
payments - see Note 9 and Note 10. The discounted cost for future decommissioning is also added to the D&P asset.
Depreciation and depletion
All costs relating to a development are accumulated and not depreciated/depleted until the commencement of
production. Depletion is calculated on a UOP basis based on the 2P reserves of the asset. Any re-assessment of
reserves affects the depletion rate prospectively. Significant items of plant and equipment will normally be fully
depreciated over the life of the field; however, these items are assessed to consider if their useful lives differ from the
expected life of the D&P asset and should this occur a different depreciation rate may be charged. The key areas of
estimation regarding depletion and the associated unit of production calculation for oil and gas assets are recoverable
reserves and future capital expenditures.
Impairment
A review is carried out for any indication that the carrying value of the Group’s D&P assets may be impaired. If any
indicators are identified, a review of D&P assets is carried out on an asset by asset basis and involves comparing the
carrying value with the recoverable value of an asset. The recoverable amount of an asset is determined as the higher
of its fair value less costs to sell and value in use. The value in use is determined from estimated future net cash flows,
being the present value of the future cash flows expected to be derived from production of commercial reserves.
Impairment resulting from the impairment testing is charged to a separate line item within the Statement of
Comprehensive Income.
The pre-tax future cash flows are adjusted for risks specific to the CGU and are discounted using a pre-tax discount
rate. The discount rate is derived from the Group’s post-tax weighted average cost of capital and is adjusted where
applicable to consider any specific risks relating to the country where the CGU is located, although other rates may be
used if appropriate to the specific circumstances. The discount rates applied in assessments of impairment are
reassessed each year. The Company uses a risk adjusted discount rate of 10%, unless otherwise stated.
The CGU basis is generally the field, however, oil and gas assets, including infrastructure assets may be accounted for
on an aggregated basis where such assets are economically inter-dependent.
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
1 Accounting policies (continued)
Oil and gas exploration, development and producing assets (continued)
4) Offshore Pipelines
Capitalisation
Costs of commissioning an offshore pipeline to transport hydrocarbons, including the cost of related onshore facilities
and subsea equipment are capitalised as a tangible asset within PPE. Each contiguous pipeline will form an exclusive
individual asset but there may be cases, such as phased developments, when pipelines are grouped together to form
a single tangible pipeline asset. The cost of offshore pipeline assets also includes the cost of acquisitions and
purchases of such assets, directly attributable overheads, applicable borrowing costs and the discounted cost of
future decommissioning.
Depreciation
All costs relating to pipeline commissioning are not depreciated until the commencement of transportation of
hydrocarbons. Depreciation is calculated on a straight-line basis over the period in which transportation is likely to take
place. Any re-assessment of this timeline will impact on the depreciation rate prospectively. The key areas of estimation
regarding depreciation are future capital expenditures and recoverable reserves for those fields where such pipelines
are utilised for the transportation of oil and gas production.
Impairment
A review is carried out for any indication that the carrying value of the pipeline asset may be impaired. If any indicators
are identified, such as the pipeline’s inability to continue to operate safely and effectively in its current environment, a
review of the pipeline asset is carried out. Impairment resulting from the impairment review is charged to a separate
line item within the Statement of Comprehensive Income.
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
1 Accounting policies (continued)
Assets other than oil and gas interests
Assets other than oil and gas interests are stated at cost, less accumulated depreciation and any provision for
impairment. Depreciation is provided at rates estimated to write off the cost, less estimated residual value, of each
asset over its expected useful life as follows: -
• Computer and office equipment: 33% straight line, with one full year’s depreciation in year of acquisition; and
• Tenants improvements: 20% straight line, with one full year’s depreciation in year of acquisition.
Provisions
Provisions are recognised when:
• the Group has a present legal or constructive obligation resulting from past events;
• it is more likely than not that an outflow of resources will be required to settle the obligation; and
• the amount can be reliably estimated.
Decommissioning
Provisions for decommissioning costs are recognised in accordance with IAS 37 Provisions, Contingent Liabilities and
Contingent Assets. Provisions are recorded at the present value of the expenditures expected to be required to settle
the Group’s future obligations.
Provisions are reviewed at each reporting date to reflect the current best estimate of the cost at present value. Any
change in the date on which provisions fall due will change the present value of the provision. These changes are
treated as an administration expense. The unwinding of the discount is reflected as a finance expense.
In the case of a D&P and/or pipeline asset, since the future cost of decommissioning is regarded as part of the total
investment to gain access to future economic benefits, this is included as part of the cost of the relevant D&P and/or
pipeline asset.
Disposals
Net proceeds from any disposal of an E&E, D&P or pipeline asset are initially credited against the previously capitalised
costs of that asset and any surplus proceeds are credited to the Statement of Comprehensive Income.
Foreign currencies
The Group’s presentational currency is GBP Sterling and has been selected based on the currency of the primary
economic environment in which the Group operates. The Group’s primary product is generally traded by reference to
its pricing in GBP Sterling. The functional currency of all companies in the Group is also considered to be GBP Sterling.
Transactions in currencies other than the functional currency of a company are recorded at a rate of exchange
approximating to that prevailing at the date of the transaction. At each balance sheet date, monetary assets and
liabilities that are denominated in currencies other than the functional currency are translated at the amounts prevailing
at the balance sheet date and any gains or losses arising are recognised in the Consolidated Statement of
Comprehensive Income.
Taxation
Current Tax
Tax is payable based upon taxable profit for the year. Taxable profit differs from net profit as reported in the Statement
of Comprehensive Income because it excludes items of income or expense that are taxable or deductible on other years
and it further excludes items that are never taxable or deductible. Any Group liability for current tax is calculated using
tax rates that have been enacted or substantively enacted by the reporting date.
Deferred Tax
Deferred tax is the tax expected to be payable or recoverable on differences between the carrying amounts of assets
and liabilities in the financial statements and the corresponding tax bases used in the computation of taxable profit.
Deferred tax liabilities are generally recognised for all taxable temporary differences and deferred tax assets are
recognised to the extent that it is probable that taxable profits will be available against which deductible temporary
differences can be utilised.
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
1 Accounting policies (continued)
Taxation (continued)
Deferred tax liabilities are recognised for taxable temporary differences arising on investments in subsidiaries, except
where the Group can control the reversal of the temporary differences and it is probable that the temporary difference
will not reverse in the foreseeable future.
The carrying amount of deferred tax assets is reviewed at each reporting date and reduced to the extent that it is no
longer probable that sufficient taxable profits will be available to allow all or part of the asset to be recovered.
Deferred tax is calculated at the tax rates that are expected to apply in the period when the liability is settled, or the
asset is realised. Deferred tax is charged or credited in the Statement of Comprehensive Income, except when it relates
to items charged or credited directly to equity, in which case the deferred tax is also dealt with in equity. Deferred tax
assets and liabilities are offset when there is a legally enforceable right to set off current tax assets against current tax
liabilities and when they relate to income taxes levied by the same taxation authority and the Group intends to settle its
current tax assets and liabilities on a net basis.
The amount of the asset or liability is determined using tax rates that have been enacted or substantively enacted by
the reporting date and are expected to apply when the deferred tax liabilities/(assets) are settled/(recovered). Deferred
tax balances are not discounted.
Investments & Loans (Company)
Non-current investments in subsidiary undertakings are shown in the Company’s Statement of Financial Position at
cost less any provision for permanent diminution of value.
Loans to subsidiary undertakings are stated at amortised cost and recognised in accordance with IFRS9. The loans
have no maturity date and are not repayable until the respective subsidiary entity has sufficient cash to repay the loan
and thus are expected to continue indefinitely.
Operating Leases
Rentals under operating leases are charged on a straight-line basis over the lease term.
Financial instruments
Financial instruments are recognised when the Group becomes a party to the contractual provisions of the instrument
and are subsequently measured at amortised cost.
Classification and measurement of financial assets
The initial classification of a financial asset depends upon the Group’s business model for managing its financial assets
and the contractual terms of the cash flows. The Group’s financial assets are measured at amortised costs and are held
within a business model whose objective is to hold assets to collect contractual cash flows and its contractual terms
give rise on specified dates to cash flows that represent solely payments of principal and interest.
The Group’s cash and cash equivalents and other receivables are measured at amortised cost. Other receivables are
initially measured at fair value. The Group holds other receivables with the objective to collect the contractual cash flows
and therefore measures them subsequently at amortised cost.
The Group has no financial assets measured at FVOCI (Fair Value Through Other Comprehensive Income) or FVTPL
(Fair Value Through the Statement of Profit or Loss)
Cash and cash equivalents
Cash includes cash on hand and demand deposits with any bank or other financial institution. Cash equivalents are
short-term, highly liquid investments that are readily convertible to known amounts of cash which are subject to an
insignificant risk of changes in value.
Impairment of financial assets
The Group recognises loss allowances for expected credit losses (‘ECL’s) on its financial assets measured at amortised
cost. Due to the nature of its financial assets, the Group measures loss allowances at an amount equal to the lifetime
ECLs. Lifetime ECLs are the anticipated ECLs that result from all possible default events over the expected life of a
financial asset. ECLs are a probability-weighted estimate of credit losses.
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
1 Accounting policies (continued)
Financial instruments (continued)
Classification and measurement of financial liabilities
A financial liability is initially classified as measured at amortised cost or FVTPL. A financial liability is classified as
measured at FVTPL if it is held-for-trading, a derivative or designated as FVTPL on initial recognition.
The Group’s accounts payable, accrued liabilities and long-term debt are measured at amortised cost.
Accounts payable and accrued liabilities are initially measured at fair value and subsequently measured at amortised
cost. Accounts payable and accrued liabilities are presented as current liabilities unless payment is not due within 12
months after the reporting period.
Long-term debt is initially measured at fair value, net of transaction costs incurred. The contractual cash flows of the
long-term debt are made up of solely principal and interest, therefore long-term debt is subsequently measured at
amortised cost. Long-term debt is classified as current when payment is due within 12 months after the reporting period.
Where warrants are issued in lieu of arrangement fees on debt facilities, the fair value of the warrants are measured at
the date of grant as determined through the use of the Black-Scholes technique. The fair value determined at the grant
date of the warrants is recognised in the Group’s warrant reserve and is amortised as a finance cost over the life of the
facility.
The Group has no financial liabilities measured at FVTPL.
The LOG loans are securitised by guarantees over the assets of IOG North Sea Limited, IOG UK Limited and IOG
Infrastructure Limited. These guarantees are considered to be insurance contracts and accounted for in accordance
with the provisions of IFRS 4.
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
1 Accounting policies (continued)
Convertible loan notes
Upon issue, convertible notes are separated into the equity and liability components at the date of issue. The liability
component is recognised initially at its fair value. Subsequent to initial recognition, it is carried at amortised carrying
value using the effective interest method until the liability is extinguished on conversion or redemption of the notes. The
equity component is the residual amount of the convertible note after deducting the fair value of the liability component.
This is recognised and included in equity and is not subsequently re-measured.
Equity
Equity instruments issued by the Company are recorded at the proceeds received, net of direct issue costs, allocated
between share capital and share premium.
Share issue expenses and share premium account
The costs of issuing new share capital are written off against the share premium account arising out of the proceeds of
the new issue.
Share-based payments
The Company and Group have applied the requirements of IFRS 2 Share-based payments. The Company issues
equity share options, to certain employees and contractors, as direct compensation for both salary and fees sacrificed
in lieu of such share options. Other Long-Term Incentive Plan (‘LTIP’) share options may be awarded to incentivise
and reward successful corporate and individual performance. The fair value of these awards has been determined at
the date of the grant of the award allowing for the effect of any market-based performance conditions.
The fair value of share options awarded, in lieu of salary sacrifice, is expensed on the effective date of grant, with no
vesting conditions applied. The fair value is deemed to be the actual salary sacrificed.
For LTIP share option awards, based upon incentive and performance, the fair value, adjusted by the estimate of the
number of awards that will eventually vest because of non-market conditions, is expensed uniformly over the vesting
period and is charged to the Statement of Comprehensive Income, together with an increase in equity reserves, over a
similar period. The fair values are calculated using an option pricing model with suitable modifications to allow for early
exercise. The inputs to the model include: the share price at the date of grant; exercise price; expected volatility;
expected dividends; risk-free rate of interest; and patterns of exercise of the plan participants. Where the terms and
conditions of options are modified before they vest, the increase in the fair value of the options, measured immediately
before and after the modification, is also charged to the Statement of Comprehensive Income over the remaining vesting
period. No expense is recognised for options that do not ultimately vest except where vesting is only conditional upon
a market condition.
Where the Group renegotiates the terms of its debt, with the result that the liability is extinguished by the issuing of its
own equity instruments to the creditor (referred to as a ‘debt for equity swap’), the equity instruments issued to settle a
liability represent ‘consideration paid’. In accordance with IFRIC 19 ‘Extinguishing Financial Liabilities with Equity
Instruments’ the Group therefore recognises a gain or loss in profit or loss when a liability is settled through the issuance
of the Group’s own equity instruments. The amount of the gain or loss recognised in profit or loss is determined as the
difference between the carrying value of the financial liability and the fair value of the equity instruments issued. The
fair value of the equity instruments issued is used to measure the gain or loss on the settlement of the existing financial
liability.
The fair value of warrants issued to third parties is calculated by reference to the service provided, or if this is not
considered possible, calculated in the same way as for LTIP share options as detailed above. Typically, these amounts
have related to debt issues and are included in the effective interest rate calculation of borrowings.
Loss/earnings per share
Loss/earnings per share is calculated as loss/profit attributable to shareholders divided by the weighted average number
of ordinary shares in issue for the relevant period. Diluted earnings per share is calculated using the weighted average
number of ordinary shares in issue plus the weighted average number of ordinary shares that would be in issue on the
conversion of all relevant potentially dilutive shares to ordinary shares adjusted for any proceeds obtained on the
exercise of any options and warrants. Where the impact of converted shares would be anti-dilutive they are excluded
from the calculation.
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
1 Accounting policies (continued)
Critical accounting judgements and key sources of estimation uncertainty
The preparation of financial statements in conformity with IFRS requires management to make judgements, estimates
and assumptions that affect the application of policies and reported amounts of assets and liabilities, income and
expenses. The estimates and associated assumptions are based on historical experience and factors that are believed
to be reasonable under the circumstances, the results of which form the basis of making judgements about carrying
values of assets and liabilities that are not clear from other sources. Actual results may differ from these estimates.
The following are the critical judgements that management has made in the process of applying the entity’s accounting
policies and that have the most significant effect on the amounts recognised in financial statements.
Impairment of assets
Management is required to assess oil and gas assets for indicators of impairment and has considered the economic
value of individual E&E and D&P assets. The carrying value of oil and gas assets is disclosed in Notes 8 and 9. The
carrying value of related investments in the Company Statement of Financial Position is disclosed in Note 11. E&E
assets are subject to a separate review for indicators of impairment, by reference to the impairment indicators set out
in IFRS 6, which is inherently judgmental.
Key estimates used in the value-in-use calculations
The calculation of value-in-use for oil and gas assets under development or in production is most sensitive to the
following assumptions:
• Commercial reserves
• production volumes;
•
commodity prices;
•
fixed and variable operating costs;
•
capital expenditure; and
• discount rates.
Commercial Reserves
Commercial reserves are proven and probable (‘2P’) oil and gas reserves, calculated on an entitlement basis. Estimates
of commercial reserves underpin the calculation of depletion and amortisation on a UOP basis. Estimates of commercial
reserves include estimates of the amount of oil and gas in place, assumptions about reservoir performance over the life
of the field and assumptions about commercial factors which, in turn, will be affected by the future oil and gas price.
Production volumes/recoverable reserves
Annual estimates of oil and gas reserves are generated internally by the Group with external input from operator profiles
and/or a Competent Person. These are reported annually by the Board. The self-certified estimated future production
profiles are used in the life of the fields which in turn are used as a basis in the value-in-use calculation.
Commodity prices
An average of published forward prices and the long-term assumption for natural UKNBP gas and Brent oil are used
for future cash flows in accordance with the Group’s corporate assumptions. Field specific discounts and prices are
used where applicable.
Fixed and variable operating costs
Typical examples of variable operating costs are pipeline tariffs, treatment charges and freight costs. Commercial
agreements are in place for most of these costs and the assumptions used in the value-in-use calculation are sourced
from these where available. Examples of fixed operating costs are platform costs and operator overheads. Fixed
operating costs are based on operator and/or third-party duty holder budgets.
Capital expenditure
Field development is capital intensive and future capital expenditure has a significant bearing on the value of an oil and
gas development asset. In addition, capital expenditure may be required for producing fields to increase production
and/or extend the life of the field. Cost assumptions are based on operator and/or service contractor cost estimates or
specific contracts where available.
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
1 Accounting policies (continued)
Critical accounting judgements and key sources of estimation uncertainty (continued)
Discount rates
Discount rates reflect the current market assessment of the risks specific to the oil and gas sector and are based on
the weighted average cost of capital for the Group. Where appropriate, the rates are adjusted to reflect the market
assessment of any risk specific to the field for which future estimated cash flows have not been adjusted. The Group
has applied a risk adjusted discount rate of 10% for the current year (2018: 10%).
Sensitivity to changes in assumptions
A potential change in any of the above assumptions may cause the estimated recoverable value to be lower than the
carrying value, resulting in an impairment loss. The assumptions which would have the greatest impact on the
recoverable amounts of the fields are production volumes (linked to recoverable reserves) and commodity prices.
Investments (Company)
If circumstances indicate that impairment may exist, investments in subsidiary undertakings of the Company are
evaluated using market values, where available, or the discounted expected future cash flows of the investment. If
these cash flows are lower than the Company’s carrying value of the investment, an impairment charge is recorded in
the Company. Evaluation of impairments on such investments involves significant management judgement and may
differ from actual results - see above.
Decommissioning
At 31 December 2018, the Group has obligations in respect of decommissioning a suspended well on the Vulcan
Satellites D&P asset, together with the acquired offshore Thames Pipeline.
The extent to which a provision is recognised depends on the legal requirements at the date of decommissioning,
regulatory activity required to ensure such infrastructure meets safety and environmental requirements, the estimated
costs and timing of the work and the discount rate applied.
A full decommissioning estimate for the Vulcan Satellites asset remains uncertain until all development infrastructure
has been installed and production volumes and time to abandonment has been considered. Prior to full development
infrastructure and commissioning, the Group will utilise technical reports, and advice from the UK Oil & Gas Authority,
to estimate costs of abandonment.
On acquisition of the Thames Pipeline, the Group assumed the decommissioning liability for the pipeline, which is based
upon a regulatory framework determined by the OGA. A discounted cost estimate provision has been made in the
financial statements as at 31 December 2018 and this provision will continue to be reviewed on an annual basis, given
the regulatory framework is subject to constant change and is inherently uncertain over future years.
The estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are
recognised in the period in which the estimate is revised, if the revision only affects that period, or, in the period of
revision and future periods, if the revision affects both current and future periods.
Fair value of share options and warrants
The fair value of options and warrants is calculated using appropriate estimates of expected volatility, risk free rates of
return, expected life of the options/warrants, the dividend growth rate, the number of options expected to vest and the
impact of any attached conditions of exercise. See above for further details of these assumptions.
2 Segmental information
The Group complies with IFRS 8, Operating Segments, which requires operating segments to be identified based upon
internal reports about components of the Group that are regularly reviewed by the directors to allocate resources to the
segments and to assess their performance. In the opinion of the directors, the operations of the Group comprise one
class of business, being the exploration and development of oil and gas opportunities in the UK North Sea.
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
3 Operating loss
The Group operating loss is stated after charging/(crediting) the following:
Fees payable to the Company's auditor:
for the audit of the Company's and Group's financial statements
-
Depreciation, depletion and amortisation
Project, pre-licence and exploration expenses
Impairment of oil and gas properties
Personnel costs – direct expenses
Personnel costs - share-based payments
Net loss on settlement of liabilities
Foreign exchange loss/(gain)
2018
£000
2017
£000
58
21
922
184
2,115
378
106
334
50
8
430
119
1,306
298
1
(333)
Of those charges above for both depreciation and personnel costs, respective sums of £12k (2017: £5k) and £1,268k
(2017: £869k) were reallocated and capitalised to oil and gas / pipeline properties.
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
4 Personnel costs and directors' remuneration
During the year, the average number of personnel, including contract personnel, for both the Company and Group was:
Management / technical / operations
of which: Directors
2018
Number
18
5
2017
Number
17
5
Personnel costs Group and Company
£000
£000
Wages, salaries, fees and other direct costs
Social security costs
Pension costs
Share-based payments
1,882
232
1
378
________
2,493
________
1,229
77
-
298
________
1,604
________
Note that project contract personnel, capitalised directly to project cost centres, are excluded from the above figures.
Key management personnel are deemed to be directors, the Chief Financial Officer and Head of Corporate Finance.
Directors’ remuneration
Salary
Share-based
payment
£000
£000
2018
Total
£000
Salary Share-based
payment
£000
£000
2017
Total
£000
Mark Routh1
Fiona MacAulay2
Mark Hughes3
David Peattie4
Martin Ruscoe
Andrew Hay5
Peter Young6
Hywel John7
Andrew Hockey
Charles Hendry
Other key management
personnel
Total key management
personnel
141
17
90
-
15
11
-
-
179
15
_______
468
_______
143
611
52
-
52
-
15
8
-
-
118
15
________
260
________
193
17
142
-
30
19
-
-
297
30
________
728
________
149
-
-
-
15
18
38
69
101
12
_______
402
_______
79
-
-
35
20
23
-
13
19
7
________
196
________
228
-
-
35
35
41
38
82
120
19
________
598
________
79
222
97
30
127
339
950
499
226
725
1 Mark Routh resigned on 31 December 2018;
2 Fiona MacAulay was appointed on 10 July 2018;
3 Mark Hughes was appointed on 18 April 2018;
4 David Peattie resigned on 21 March 2017;
5 Andrew Hay resigned on 13 February 2018;
6 Peter Young resigned on 21 March 2017;
7 Hywel John was appointed on 21 March 2017, resigned on 13 September 2017
The salary amounts are those cash amounts paid to directors and key management personnel during the year. The share-based
payment amounts represent the fair value of options issued and/or expensed in the year, for both LTIPs and those in lieu of cash
salary and/or director fees paid.
In addition to the above, an amount of £470 was paid in employer pension contributions for Mark Hughes.
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
4 Personnel costs and directors' remuneration (continued)
Social security costs for the year for key management personnel were £134k (2017 - £53k).
For the current directors at 31 December 2018, the service agreements for Mark Hughes, Andrew Hockey, Martin
Ruscoe and Charles Hendry provide that only a proportion of the full contractual amount will be paid in cash with the
balance to be settled in share options granted.
The proportions paid in 2018 for all directors were 100% for Fiona MacAulay, 75% for each of Mark Routh, Andrew
Hockey, Mark Hughes and other key management personnel and 50% for Martin Ruscoe, Andrew Hay and Charles
Hendry. For each six-month interval, ending on 28 (or 29) February and 31 August respectively, the Company settles
the difference between the reduced rate and the full rate through the granting of options over ordinary shares of the
Company at the volume-weighted average share price over the period to which they relate. Amounts of salary and/or
fees outstanding at 31 December 2018 to which these terms relate totalled £76k (31 December 2017 – £60k) for
directors and key management personnel and £11k (2017 - £9k) for other personnel. These were subsequently settled
in share options, issued on 1 March 2019.
Directors’ interests in options on 1p ordinary shares of the Company at 31 December 2018 were as follows:
Granted
Total
31 Dec 2017
Awarded /
(Exercised) in
2018
Total
31 Dec
2018
Exercise
price
Expiry date
Andrew Hockey
Mark Hughes
Martin Ruscoe1
Charles Hendry
1 Sep 2017
1 Mar 2018
1 Mar 2018
1 Sep 2018
27 Jul 2018
1 Sep 2018
1 Sep 2017
1 Mar 2018
1 Sep 2018
1 Sep 2017
1 Mar 2018
1 Sep 2018
110,800
-
-
-
-
102,537
1,600,000
128,700
110,800
102,537
1,600,000
128,700
-
-
1,000,000
62,417
1,000,000
62,417
44,699
-
-
39,745
-
-
-
34,179
30,888
-
34,179
30,888
44,699
34,179
30,888
39,745
34,179
30,888
1p
1p
20p
1p
35p
1p
1p
1p
1p
1p
1p
1p
31 Aug 2022
28 Feb 2023
28 Feb 2028
31 Aug 2023
27 July 2028
31 Aug 2023
31 Aug 2022
28 Feb 2023
31 Aug 2023
31 Aug 2022
28 Feb 2023
31 Aug 2023
1 Options granted to South Riding Consultancy Limited, a company in which Martin Ruscoe is a majority shareholder and a director.
____________________________________________________________________________________________________________________
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
5 Finance expense
Interest on loans
Interest on deferred payment creditors
Amortisation of loan finance charges
Current year loan finance charges
Current year finance charges on deferred payment creditors
Unwinding of deferred consideration provisions
2018
£000
1,493
373
617
49
-
592
2017
£000
1,092
12
411
44
122
153
________
________
3,124
1,834
________
_________
6 Taxation
a) Current taxation
There was no tax charge during the year as the Group loss was not chargeable to corporation tax. Applicable
expenditures to-date will be accumulated for offset against future tax charges.
The reasons for the difference between the actual tax charge for the year and the standard rate of corporation tax in
the United Kingdom applied to profits for the year are as follows:
Loss for the year
Income tax expense
Loss before income taxes
Expected tax credit based on the standard rate of United Kingdom
corporation tax at the domestic rate of 40% (2017: 40%)
Difference in tax rates
Expenses / (income) not deductible for tax purposes
Income not taxable/allowable
Unrecognised taxable losses carried forward
Total tax expense
b) Deferred taxation
2018
£000
2017
£000
(5,644)
-
_________
(5,644)
(2,751)
-
_________
(2,751)
(2,258)
(1,100)
826
137
(2,617)
3,912
_________
-
_________
(244)
(220)
(3,107)
4,671
_________
-
_________
Due to the nature of the Group's E&P activities there is a long lead time in either developing or otherwise realising E&P
assets. The amount of deductible temporary differences, unused tax losses and unused tax credits for which no deferred
tax asset is recognised in the statement of financial position is £80.72 million (2017: £57.72 million). Included within this
figure are accelerated capital allowances of £32.6 million (2017: £18.1 million).
The Group has not recognised a deferred tax asset at 31 December 2018 on the basis that the Group would expect the
point of recognition to be when the Group has some level of production history showing that the Group is making profits
in line with the underlying economic model which would support the recognition.
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
7 Loss per share
Loss for the year attributable to shareholders
2018
£000
2017
£000
(5,644)
(2,751)
___________ ___________
Weighted average number of ordinary shares – basic and diluted
123,581,926
109,538,499
___________ ___________
Loss per share in pence – basic and diluted
4.6p
2.5p
Diluted loss per share is calculated based upon the weighted average number of ordinary shares plus the weighted
average number of ordinary shares that would be issued upon conversion of potentially dilutive share options and
warrants into ordinary shares. As the result for 2018 was a loss, the options and warrants outstanding would be anti-
dilutive. Therefore, the dilutive loss per share is considered as the same as the basic loss per share.
____________________________________________________________________________________________________________________
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
8
Intangible assets
Group
At cost
At beginning of the year
Additions
Disposals
Reclassified as Development &
Production assets
At end of the year
Impairments and write-downs
At beginning of the year
DD&A
Net Impairment
Disposals
At end of the year
Net book value
At 31 December 2018
A t 1 January 2018
At 1 January 2017
Exploration
&
evaluation
assets
Company
& IT
software
assets
Total Exploration
&
evaluation
assets
Company
& IT
software
assets
Total
2018
£000
22,402
2,351
(34)
-
2018
£000
2018
£000
2017
£000
2017
£000
2017
£000
3
4
-
-
22,405
2,355
(34)
27,923
1,484
-
-
(7,005)
3
-
-
-
27,926
1,484
-
(7,005)
_________ _________ ________
________ ________ ________
24,719
24,726
_________ _________ ________
7
22,402
22,405
________ ________ ________
3
(22,217)
-
(184)
34
(2)
(2)
-
-
(22,219)
(22,098)
(2)
(184)
34
-
(119)
-
(1)
(1)
-
-
(22,099)
(1)
(119)
-
_________ _________ ________
________ ________ ________
(22,367)
(22,371)
_________ _________ ________
(4)
(22,217)
(22,219)
________ ________ ________
(2)
2,352
185
5,825
3
1
2
2,355
186
5,827
____________________________________________________________________________________________________________________
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
8
Intangible assets (continued)
E&E assets at 31 December 2018 comprise the Group’s interest in the Harvey and Abbeydale appraisal prospects and
the Goddard pre-development prospect.
An impairment charge of £184k was recognised during the year reflecting those post 2016 drilling expenses and licence
administration costs incurred on the previously impaired Skipper asset, Licence P1609. Licence P2122 which had been
relinquished in 2017, was formally released from the balance sheet in 2018.
9 Property, plant and equipment
Group
D&P
assets
Pipeline
assets
Company &
admin
assets
Total
D&P assets
Company &
admin assets
Total
At cost
At beginning of the year
Additions
Reclassified from current
assets
Initial Thames Pipeline
decommissioning security
Reclassified from E&E
assets (see Note 8)
Blythe asset acquisition
(Note 10)
Vulcan Satellites asset
acquisition (Note 10)
At end of the year
Accumulated
depreciation
At beginning of the year
DD&A
At end of the year
Net book value
At 31 December 2018
At 1 January 2018
At 1 January 2017
2018
£000
2018
£000
2018
£000
2018
£000
21,316
-
9,676
10,447
34
40
21,350
20,163
-
500
-
-
-
-
-
-
-
-
200
500
-
(392)
(220)
200
-
-
(392)
(220)
________
30,580
________
2017
£000
7,506
825
-
-
7,005
3,078
2,902
2017
£000
2017
£000
30
4
7,536
829
-
-
-
-
-
-
-
7,005
3,078
2,902
______ _________
______
_________ _________
______
10,947
74
41,601
21,316
34
21,350
______ _________
______
_________ _________
______
-
-
________
-
________
-
-
(14)
(19)
(14)
(19)
-
-
(6)
(8)
(6)
(8)
______ _________
______
_________ _________
______
-
(33)
(33)
-
(14)
(14)
______ _________
______
_________ _________
______
30,580
21,316
7,506
10,947
-
-
41
20
24
41,568
21,336
7,530
All development and production assets are awaiting approval from the OGA expected 31 March 2019.
Amounts paid as decommission security guarantees in respect of both the Elland P039 Licence suspended well, £200k
(paid on acquisition to the prior owners of the Vulcan Satellites in October 2016 and previously held as a current asset)
and the Initial Thames Pipeline Decommissioning Security, £500k (paid on completion of the Thames Pipeline
acquisition in April 2018) have been classified as fixed assets at 31 December 2018.
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
10 Asset Acquisitions
Vulcan Satellites
On 28 October 2016, the Company announced the completion of the acquisition of Oyster Petroleum Limited, from
Verus Petroleum, comprising the Vulcan Satellites. This has been accounted for as an asset acquisition given the
status of the projects held by Oyster Petroleum on the acquisition date. Under the terms of the agreement the Company
paid £1 million, plus interim cash adjustments payable at completion. In accordance with the Vulcan Satellites purchase
agreement a further £0.75 million was payable nine months after completion and was subsequently paid on 1 August
2017. Further payments of £3.25 million are payable upon achievement of certain further milestones which are;
• £1.75 million on FDP approval and
• £1.50 million on first gas production.
After further work on the project during 2017 and 2018, the achievement of future milestones, which are now considered
more certain than not and as the transaction was considered an asset acquisition, these future payments have therefore
been recognised in the financial statements and recorded within the cost base of the Vulcan Satellites asset. See Note
15 for further details.
At 1 January
Milestone payments recognised within D&P assets
Discount adjustment on future milestone payments
At 31 December
Blythe
2018
£000
2,902
-
(220) (Note 9)
2,682
2017
£000
-
2,902 (Note 9)
-
2,902
On 21 June 2016, the Company announced the completion of the additional 50% operated stake in the Blythe field,
thereby increasing its interest to 100%. The consideration comprised an upfront payment of £1.50 million, plus interim
cash adjustments payable at completion with deferred consideration of a further USD 5.00 million to be paid at first gas
production.
Given the USD 5.00 million is dependent on achievement of a future milestone event, which is now considered more
certain than not, and the transaction is considered an asset acquisition, this amount of £3,078k has now been
recognised in the financial statements and recorded within the cost base of the Blythe asset. See Note 15 for further
details.
At 1 January
Milestone payments recognised within D&P assets
Discount adjustment on future milestone payments
At 31 December
2018
£000
3,078
-
2017
£000
-
3,078 (Note 9)
(392) (Note 9)
2,686
-
3,078
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
11 Investments
Company
At cost
At 1 January 2017
Additions
At 31 December 2017
Additions
At 31 December 2018
Impairment
At 1 January 2017
Impairment reversal
At 31 December 2017
Impairment
At 31 December 2018
Net book value
At 31 December 2018
At 1 January 2018
At 1 January 2017
Shares
in Group
companies
Loans
to Group
companies
£000
£000
14,514
2,902
_________
17,416
(219)
_________
17,197
-
-
_________
-
-
_________
-
11,995
285
_________
12,280
17,246
_________
29,526
(1,870)
1,870
_________
-
-
_________
-
Total
£000
26,509
3,187
_________
29,696
_________
(1,870)
1,870
_________
-
-
_________
-
17,197
17,416
29,526
12,280
46,723
29,696
14,514
10,125
24,639
The Company has undertaken not to seek repayment of loans from other Group subsidiary companies until each
subsidiary has sufficient funds to make such payments however they are technically due on demand. These loans are
non-interest bearing.
The impairment of £1.87 million taken on loans to Group companies in prior years was reversed in 2017.
The Company's subsidiaries, all registered at 60 Gracechurch Street, London EC3V 0HR, are as follows:
Directly held
IOG Infrastructure Limited
IOG North Sea Limited
IOG UK Limited
Avalonia Energy Limited (dormant)
Avalonia Goddard Limited (dormant)
Avalonia Abbeydale Limited (dormant)
Country of
incorporation
United Kingdom
United Kingdom
United Kingdom
United Kingdom
United Kingdom
United Kingdom
Area of
operation
United Kingdom
United Kingdom
United Kingdom
United Kingdom
United Kingdom
United Kingdom
%
100
100
100
100
100
100
IOG Infrastructure Limited completed the Thames Pipeline acquisition on 16 April 2018 and became an active subsidiary
at that time. All three active subsidiaries are now engaged in the business of oil and gas appraisal, development and/or
operations in the UK North Sea.
The three dormant companies were incorporated in 2H18 and have been made available to support any potential Group
restructure following refinancing of the Group.
The financial reporting periods for each subsidiary entity are consistent with the Company and end on 31 December.
____________________________________________________________________________________________________________________
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
12 Interests in production licences
All ten Group UK Offshore Production Licences, held at 31 December 2018, are owned 100% by either IOG North Sea
Limited or IOG UK Limited. The Thames Pipeline P370 asset is owned 100% by IOG Infrastructure Limited.
13 Other receivables and prepayments
Group
VAT recoverable
Prepayments
Debtors
Decommissioning guarantees (Note 9)
Company
VAT recoverable
Prepayments
Debtors
2018
£000
2017
£000
311
361
-
-
_________
672
_________
311
361
-
_________
672
_________
285
465
18
200
_________
968
_________
285
465
17
_________
767
_________
Included in 2018 Prepayments (both Group and Company) are financing costs of £291k (2017: £nil) incurred, cumulative
at 31 December 2018, on progressing further refinancing for the Company and Group. These will be either transferred
to equity (share capital issue costs), set off against debt, or expensed to the Statement of Comprehensive Income,
dependent upon the outcome of such refinancing. Included in 2017 Prepayments (both Group and Company) is capital
of £408k representing expenditure incurred, cumulative to date at 31 December 2017, on progressing the Thames
Pipeline deal acquisition and completion. This was transferred to PPE within the Group on acquisition completion of the
Thames Pipeline facility in April 2018.
14 Current liabilities
Group
Loans
Trade payables
Accruals
Contingent consideration payable (see Note 15)
Company
Trade payables
Accruals
Contingent consideration payable (see Note 15)
2018
£000
2017
£000
6,934
5,961
3,467
1,709
_________
18,071
_________
5,961
401
1,709
_________
8,071
_________
-
4,827
569
1,642
_________
7,038
_________
4,827
174
1,642
_________
6,643
_________
Accruals for the Group have increased significantly in the period, due to the value of SNS Project work undertaken for
the year to 31 December 2018, which remains unbilled by vendors and suppliers as at 31 December 2018.
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
14 Current liabilities (continued)
Of the Group’s current liabilities at 31 December 2018:
• £6.93 million (2017: £nil) was owing to LOG consisting £5.54 million principal and £1.39 million interest.
These loans accrue interest at LIBOR+9%. See also below Note 15;
• Trade payables consist Skipper deferred creditors £2.22 million (2017: £4.46 million), SNS Project creditors
£3.42 million (2017: £0.18 million) and other creditors £0.32 million (2017: £0.19 million);
• Accrued expenditures consist SNS Projects £3.07 million (2017: £0.42 million) and other accruals £0.40
million (2017: £0.15 million); and
• Verus Petroleum deferred consideration payable £1.71 million (2017: £1.64 million).
15 Non-current liabilities
Group
Long-term loans
Contingent consideration payable
Decommissioning provision
Company
Long-term loans
Contingent consideration payable
2018
£000
22,884
4,478
5,640
_________
33,002
_________
14,054
1,259
_________
15,313
_________
Long-term loans:
The amounts drawn on LOG loans at 31 December 2018 were as follows:
Loan Facility
£2.75 million facility1
£0.80 million facility1
£10.00 million facility2
£10.00 million facility2
£15.00 million facility1
Entity
Effective Date
Principal
IOG North Sea Limited
7 December 2015
£2.75 million
IOG North Sea Limited
11 December 2015
£0.80 million
IOG North Sea Limited
5 February 2016
£10.00 million
IOG plc
IOG plc
21 February 2018
£10.00 million
13 September 2018
£7.15 million
2017
£000
12,394
4,371
3,598
_________
20,363
_________
-
1,259
_________
1,259
_________
Interest
£0.66 million
£0.19 million
£1.67 million
£0.67 million
£0.14 million
1 Warrants were issued to LOG in respect of these facilities. The valuation of these warrants is detailed in Note 16 and
is amortised over the life of the facilities.
2 Both these 2016 and 2018 £10.00 million loans are convertible into ordinary shares of 1p in the Company at 8p and
19p respectively.
The balance on the Group’s long-term loans at 31 December 2018 is represented by drawings of £30.70 million (2017:
£11.91 million) plus accrued interest of £3.33 million (2017: £1.09 million) on these LOG facilities, less the non-
amortised value £4.21 million (2017: £0.61 million) of loan finance (which includes both the non-amortised amount of
warrants as detailed above and prepaid financing costs), less the £6.93 million included in current liabilities (2017: £nil).
Interest accrued during the year was £2.24 million (2017: £0.88 million) of which £0.75 million (2017: £0.02 million) has
been capitalised to SNS Projects
The interest rate on all LOG loans is LIBOR+9% for the duration of the term other than the September 2018 £15.00
million facility where the rate increases to LIBOR+11% from 1 December 2018. These interest rates are determined as
market debt rates and hence no equity element has been recognised for either of the £10.00 million convertible loans.
The LOG loans are securitised by guarantees over the assets of IOG North Sea Limited, IOG UK Limited and IOG
Infrastructure Limited. These guarantees are considered to be insurance contracts and accounted for in accordance
with the provisions of IFRS 4.
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
15 Non-current liabilities (continued)
Contingent consideration payable:
As indicated in Note 10, the Group is required under the terms of the 2016 acquisition of the additional 50% of Blythe
and the 2016 acquisition of Vulcan Satellites, to make further amounts payable on both the FDP approval (Vulcans),
being a current liability expected 31 March 2019, and first gas (Blythe and Vulcans) being non-current liabilities, see
below.
As disclosed in the 2017 financial statements, these milestone events triggering deferred consideration payments are
now considered to be more certain than not and a non-current amount of £4.37 million was recognised. These amounts
have been provided for and the payments discounted to the point where the Board expect the milestones to be achieved
based on the current development programme. Timings for these non-current payments, pursuant to first gas, are now
anticipated to be 31 October 2020 (Vulcans) and 31 January 2021 (Blythe).
The movements in the year are as follows:
at 1 January
Additional Blythe consideration
Additional Vulcans consideration
Prospective adjustment for change in payment dates
(Note 10)
Foreign exchange
Unwinding of discount
at 31 December
2018
£000
6,013
-
-
(612)
194
592
6,187
2017
£000
-
3,078
2,901
-
(118)
152
6,013
Given the timing of the expected payments, the total balance is split between current and non-current as below:
Current contingent consideration payable (FDP
approval)
Non-Current contingent consideration payable (first gas)
2018
£000
1,709
4,478
6,187
2017
£000
1,642
4,371
6,013
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
15 Non-current liabilities (continued)
Decommissioning provision:
at 1 January
additions: Thames Pipeline
At 31 December
2018
£000
3,598
2,042
5,640
2017
£000
3,598
-
3,598
The Group has regulatory and financial obligations in respect of decommissioning a suspended well on the Elland
Licence P039 - £3.60 million (2017: £3.60 million) and decommissioning the Thames Pipeline - £2.04 million (2017:
£nil).
A full decommissioning estimate for the Elland suspended well remains uncertain until an appropriate drilling
programme has been reviewed and considered for the Elland development, which may include the abandonment of
that particular well. The timing and thus payment of this decommissioning program remains inherently uncertain. As per
Note 1, the current estimate of £3.60 million is based upon a recent technical valuation.
The £2.04 million provision for the Thames Pipeline decommissioning obligation has been calculated on a discounted
cash flow basis, whereby the present value of the regulatory marine surveys has been inflated at 2% and then
discounted at the risk-free discount rate of 1.8%. It has been estimated that the Thames Pipeline has a useful life over
the next 25 years; however, the judgements made on this and other variables, currently provided by the OGA, are
inherently uncertain.
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
16 Equity share capital
Authorised, allotted, issued and fully
paid
At 1 January 2017
- Ordinary shares of 1p each
Equity issued
Creditor settlement via issue of shares
At 31 December 2017
- Ordinary shares of 1p each
Equity issued
At 31 December 2018
- Ordinary shares of 1p each
Number
Share
capital
£000
Share
premium
£000
Total
£000
109,268,163
462,206
10,479,260
_________
1,093
5
105
_________
20,460
-
1,877
_________
21,553
5
1,982
_________
120,209,629
1,203
22,337
23,540
6,658,527
_________
66
_________
-
_________
66
_________
126,868,156
_________
1,269
_________
22,337
_________
23,606
_________
2017:
During 2017, the Company issued 462,206 ordinary shares at a subscription price of 1p from the exercise of
management and other personnel share options.
On 29 December 2018, the Company issued 10,479,260 ordinary shares in lieu of Skipper creditor settlement cash
payments to both GE Oil & Gas UK Limited and AGR Well Management Limited.
2018:
During 2018, the Company issued 6,658,527 ordinary shares at a subscription price of 1p from the exercise of
management and other personnel share options.
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
16 Equity share capital (continued)
Share options and warrants
During the current and prior year, the Company granted share options under its share option plans as follows:
1 January 2017
Salary/fee sacrifice options
Salary/fee sacrifice options
Salary/fee sacrifice options
Options exercised
31 December 2017
Salary/fee sacrifice options
LTIP options
LTIP options
Salary/fee sacrifice options
Options exercised
Number
Price Date of Grant
Expiry
11,029,143
905,099
5,718
845,912
(462,206)
12,323,666
483,166
2,600,000
1,000,000
534,420
(6,658,527)
1p
1p
1p
1p
1p
1p
20p
35p
1p
1 Mar 2018
28 Jun 2017
1 Sep 2017
28 Feb 2023
28 Jun 2022
31 Aug 2022
1 Mar 2018
1 Mar 2018
27 Jul 2018
1 Sep 2018
28 Feb 2023
28 Feb 2028
26 Jul 2028
31 Aug 2023
31 December 2018
10,282,725
9.11p
Of the remaining personnel options, 11,029,143 outstanding at 1 January 2017, 308,860 were exercised during 2017.
Of those personnel options granted during 2017, 153,346 were exercised during 2017. Total personnel options
exercised in 2017 is thus 462,206.
Of the remaining staff options, 12,323,66, outstanding at 31 December 2017, 6,652,717 were exercised during 2018.
Of those staff options granted during 2018, 5,810 were exercised during 2018. Total personnel options exercised in
2018 is thus 6,658,527.
The fair value of these options exercised was transferred from the Share-based Payment Reserve to Accumulated
Loss.
All salary/fee sacrifice options outstanding at 31 December 2018 were issued at an exercise price of 1p per share and
carry no additional performance conditions. All LTIP options outstanding at 31 December 2018 were issued to option
holders with, other than the target price, several performance criteria including the delivery, measurement, control and
management of an appropriate HSE statement and policy together with a Group-wide HSE focussed culture.
The remaining average contractual life of the 10,282,725 options outstanding at 31 December 2018 (2017 – 12,323,666)
was 4.91 years at that date (2017 – 2.14 years) of which 6,682,725 were exercisable at 31 December 2018 (2017 – all
12,323,666 options were exercisable at 31 December 2017).
The weighted average exercise price of the options remaining was 9.11p at 31 December 2018 (2017 – 1p).
A further 612,856 options were exercised during March 2019; however, no further share options have been issued
during 2019 as at the date of this report.
The Company calculates the value of personnel salary/fee sacrificed share-based compensation as the actual value of
the sacrificed amount. This is deemed to be the fair value of such awards. The fair value of sacrificed salary/fee share
options granted in 2018 is calculated as £236k (2017 - £298k) and this has been charged to the Statement of
Comprehensive Income. The exercise price of such awards was determined as 1p (2017 – 1p).
The Company calculates the fair value of LTIP share-based compensation using a Black-Scholes options pricing model.
The fair value of LTIP options granted in 2018 is calculated as £633k (2017 - £nil), of which £141k (2017 - £nil) has
been charged to the Statement of Comprehensive Income, being the amortised amount over the vesting period
attributable to the current year. The exercise price of these options has been determined as 20p for those issued on 1
March 2018 and 35p for those issued on 27 July 2018.
Further details for directors are provided in Note 4.
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
16 Equity share capital (continued)
The Company has granted warrants in the current year as follows (2017: lapsed warrants):
Number
Price Date of Grant
Expiry
1 January 2017
14,103,397
10.48p
Lapsed – Darwin Strategic
(326,087)
31 December 2017
13,777,310
9.64p
London Oil & Gas Ltd
20,000,000
32.18p
13 Sep 2018
12 Sep 2023
31 December 2018
33,777,310
22.98p
326,087 warrants awarded to Darwin Strategic in June 2014 expired and lapsed on 4 September 2017. Accordingly,
the fair value of these awards was transferred from the Share-based Payment Reserve to Accumulated Loss.
The Company calculates the value of share-based compensation using the Black-Scholes option pricing model to
estimate the fair value of warrants at the date of grant.
The fair value of 20,000,000 warrants granted to London Oil & Gas Limited on 13 September 2018 was calculated as
£4.19 million, all of which was recognised as an issue cost of the £15 million LOG loan facility, held at amortised cost
using the effective interest method. The exercise price of these warrants was determined as 32.18p.
The following assumptions were applied in the LOG warrant award calculation:
Risk free interest rate
Dividend yield
Weighted average life expectancy
Volatility factor
1.50%
nil
4 years
96.45%
A volatility of 96.45% has been applied based upon the Company’s share price over the period from the Company’s
listing on AIM on 30 September 2013 until 13 September 2018.
The remaining average contractual life of the 33,777,310 warrants outstanding at 31 December 2018 (2017 –
13,777,310) was 3.18 years at that date (2017 – 1.97 years). All such warrants were exercisable at 31 December 2018.
The weighted average exercise price of the warrants remaining was 22.98p at 31 December 2018 (2017 – 9.64p). No
further warrants have been issued or exercised as at 28 March 2019.
17 Cash and cash equivalents
Group and Company
Cash at bank
2018
£000
2017
£000
702
_________
145
_________
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
18 Company loss for the year
The Company has taken advantage of the exemption allowed under Section 408 of the Companies Act 2006 and has
not presented its own Statement of Comprehensive Income in these financial statements.
The Company loss for the year was £2,604k (2017: profit £1,176k).
19 Operating Leases
Minimum lease payments under operating leases recognised
as a gross expense in the year
Group
2018
£000
73
2017
£000
64
Minimum lease payments under operating leases recognised
as capital expenditure in the year
87
-
Company
2018
£000
73
-
2017
£000
64
-
At 31 December 2018, outstanding commitments for operating lease payments fall due as follows:
Within one year
In the second to fifth year inclusive
Group
2018
£000
187
454
2017
£000
73
200
Company
2018
£000
2017
£000
73
126
73
200
Operating lease payments represent the Group and Company’s share of office lease rental payments at 10 Arthur
Street, London EC4R 9AY, together with the Crown Estate lease for the rights for the Thames Pipeline to cross the
foreshore at Bacton.
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
20 Financial instruments
Significant accounting policies
Details of the significant accounting policies in respect of financial instruments are disclosed in Note 1 of the financial
statements.
Financial risk management
The Board seeks to minimise its exposure to financial risk by reviewing and agreeing policies for managing each
financial risk and monitoring them on a regular basis. At this stage, no formal policies have been put in place to hedge
the Group and Company's activities to the exposure to currency risk or interest risk and no derivatives or hedges were
entered during the year.
General objectives, policies and processes
The Board has overall responsibility for the determination of the Group and Company's risk management objectives
and policies and, whilst retaining ultimate responsibility for them, it has delegated the authority for designing and
operating processes that ensure the effective implementation of its objectives and policies to the Group's finance
function. The Board receives regular reports from the Chief Financial Officer through which it reviews the effectiveness
of the processes put in place and the appropriateness of the objectives and policies it sets.
The Group is exposed through its operations to the following financial risks:
• Liquidity risk;
• Credit risk;
• Cash flow interest rate risk; and
• Foreign exchange risk
The overall objective of the Board is to set policies that seek to reduce risk as far as possible without unduly affecting
the Group and Company's competitiveness and flexibility. Further details regarding these policies are set out below.
Principal financial instruments
The principal financial instruments used by the Group and Company, from which financial instrument risk may arise are
as follows:
• Cash and cash equivalents
• Loans
• Trade and other payables
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
20 Financial instruments (continued)
Liquidity risk
The Group and Company's policy is to ensure that it will always have sufficient cash to allow it to meet its liabilities
when they become due. To achieve this aim, it seeks to maintain readily available cash balances supplemented by
borrowing facilities sufficient to meet expected requirements for a period of at least twelve → eighteen months for
personnel costs, overheads, working capital and as commitments dictate for capital spend.
Rolling cash forecasts, which are essentially the current budgeting and reforecasting process, identifying the liquidity
requirements of the Group and Company, are produced frequently. These are reviewed and approved regularly by
management and the Board to ensure that sufficient financial resources are made available. The Group’s oil and gas
exploration and development activities are currently funded through the Company. The Board has identified that further
funds will be required within the next twelve months and are implementing various courses of action as detailed in the
Finance Review to ensure that adequate funding is available.
2018 Group
Current financial assets
Cash and cash equivalents
Current financial liabilities
Trade and other payables
Deferred consideration
Accruals
Loans
Non-current financial liabilities
Deferred Consideration
Loans
Decommissioning Provisions
2017 Group
Current financial assets
Cash and cash equivalents
Current financial liabilities
Trade and other payables
Non-current financial liabilities
Provisions
Loans
6 months
or less
£000
702
________
702
________
6,017
1,750
3,467
3,138
-
-
-
________
14,372
________
145
________
145
________
Greater than
6 months, less
than 12 months
£000
Greater
than
12 months
£000
Total
undiscounted
£000
Carrying
amount
£000
-
_________
-
________
702
_________
702
________
-
_________
-
________
702
_________
702
________
-
-
-
4,213
-
-
-
-
6,017
1,750
3,467
7,351
5,961
1,709
3,467
6,934
-
-
-
_________
5,426
34,118
6,291
________
5,426
34,118
6,291
_________
4,478
22,884
4,331
________
4,213
_________
45,835
________
64,420
_________
49,764
________
-
_________
-
________
145
_________
145
________
-
_________
-
________
145
_________
145
________
1,225
5,979
208
7,412
7,038
-
-
________
1,225
________
-
-
5,206
15,705
________
_________
5,206
15,705
_________
4,371
13,000
________
5,979
_________
21,119
________
28,323
_________
24,409
________
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
20 Financial instruments (continued)
2018 Company
Current financial assets
Cash and cash equivalents
Loans to Group companies
Current financial liabilities
Trade and other payables
Deferred Consideration
Accruals
Non-current financial liabilities
Deferred Consideration
Loans
2017 Company
Current financial assets
Cash and cash equivalents
Loans to Group companies
Current financial liabilities
Trade and other payables
Non-current financial liabilities
Deferred Consideration
6 months
or less
£000
702
-
________
702
________
6,017
1,750
402
-
-
________
8,169
________
145
-
________
145
________
Greater than
6 months, less
than 12 months
£000
Greater
than
12 months
£000
Total
undiscounted
£000
Carrying
amount
£000
-
-
_________
-
29,526
________
702
29,526
_________
702
29,526
________
-
_________
29,526
________
30,228
_________
30,228
________
-
-
-
-
-
-
6,017
1,750
402
5,961
1,709
402
-
-
_________
1,500
23,543
________
1,500
23,543
_________
1,259
14,054
________
-
_________
25,043
________
33,212
_________
23,385
________
-
-
_________
-
12,280
________
145
12,280
_________
145
12,280
________
-
_________
12,280
________
12,425
_________
12,425
________
1,038
5,979
-
7,017
6,643
-
________
1,038
________
-
_________
1,500
________
1,500
_________
1,259
________
5,979
_________
1,500
________
8,517
_________
7,902
________
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
20 Financial instruments (continued)
Credit risk
Credit risk arises principally from the Group’s and Company’s other receivables, cash and cash equivalents, and loans
to subsidiaries (Company). It is the risk that the counterparty fails to discharge its obligation in respect of the instrument.
The credit risk on liquid funds is limited because the counterparties are banks with credit ratings assigned by
international credit rating agencies. The Group places funds only with selected organisations with ratings of 'A' or above
as ranked by Standard & Poor's for both long and short-term debt. All funds are currently placed with the National
Westminster Bank plc. IFRS 9 provides an updated framework for the accounting recognition and treatment of the
Group’s and Company’s other receivables held. The Group and Company adopted IFRS 9 in this financial year.
Management have chosen not to apply the standard retrospectively on the basis of the impact not being material, both
in terms of impairment or additional Expected Credit Losses (‘ECLs’) recognised. The Company has assessed that the
resulting impact on the financial statements is not material.
The Group made investments and advances into subsidiary undertakings during the year and these mostly relate to the
funding of the SNS Hub Development Projects, and the Company expects to recover these loans when these Projects
start to generate positive cash flows. Loans to subsidiary undertakings are recognised at amortised cost in accordance
with IFRS 9. The loans have no maturity date and are not repayable until the respective subsidiary entity has sufficient
cash to repay the loan. The Board has accordingly assessed the expected repayment dates based on the strategic
forecasts approved by the Board.
As at the Balance Sheet date, the Group and Company do not have any other external receivables (2017: £17k).
IFRS 9 introduces a new impairment model that requires the recognition of ECLs on financial assets at amortised cost.
The ECL computation must also consider forward looking information to recognise impairment allowances earlier. IFRS
9 consequently is likely to increase the volatility of impairment allowances as the economic outlook changes although
cash flows and cash losses are expected to remain unchanged. Intercompany exposures, where appropriate, are also
in scope under IFRS 9. The Company has assessed the loans made to subsidiary undertakings on the basis of the
relevant subsidiaries’ long-term strategic forecasts and alongside the Board’s commercial rationale for providing the
specific loan. The loans are not repayable on demand and are expected to be repaid once the underlying assets
progress into the production phase when cash inflows are generated. Based on the methodology set out by the
standard, the Board has for each intercompany loan, assessed the probability of the default, the loss given default and
the expected exposure to compute the ECLs. The Board has incorporated relevant medium and long-term
macroeconomic forecasts in their assessment which is included as a principle consideration in the entity’s strategic
forecasts. Such factors include oil price sensitivities, funding requirements, reserve and resource estimates. The Board
has concluded that any ECLs to be recognised are not material to these financial statements and that there has been
no significant increase in credit risk that would warrant the recognition of a material provision. Accordingly, the Company
has not recognised any expected credit loss for the balances owed by subsidiary undertakings recognised on the
Balance Sheet at amortised cost. The Group and Company do not hold any collateral as security for any external
financial instruments, or otherwise.
The maximum exposure to credit risk is the same as the carrying value of these items in the financial statements as
shown below.
Other receivables
Loans to subsidiaries
Cash and cash equivalents
Group
Company
2018
£000
2017
£000
2018
£000
2017
£000
-
-
702
17
-
145
-
17
29,526
12,280
702
145
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
20 Financial instruments (continued)
Cash flow interest rate risk
Cash is essentially non-interest bearing. Loans and trade creditors are subject only to fixed interest rates (albeit with
low volatility LIBOR+ variation); accordingly, commercial interest rates would have no significant impact upon the
Group’s and Company’s result for the year ended 31 December 2018 (nor 31 December 2017).
Foreign exchange risk
At 31 December 2018, the Group’s and Company’s monetary assets and liabilities are denominated in GBP Sterling,
the functional currency of the Group and each of its subsidiaries, other than USD 1,848k (£1,451k), EURO 717k (£644k)
and NOK 891k (£81k) of current liabilities held by the Group and Company and USD 4,100k (£3,219k) of long-term
liabilities held by the Group. This exposure gives rise to net currency gains and losses recognised in the Statement of
Comprehensive Income.
A 10% fluctuation in the GBP sterling rate compared to USD would give rise to a £425k gain or £519k loss in the Group’s
Statement of Comprehensive Income and a £132k gain or £161k loss in the Company’s Statement of Comprehensive
Income.
A 10% fluctuation in the GBP sterling rate compared to EURO would give rise to a £58k gain or £72k loss in the Group
and Company’s Statement of Comprehensive Income.
A 10% fluctuation in the GBP sterling rate compared to NOK would give rise to a £8k gain or £9k loss in the Group and
Company’s Statement of Comprehensive Income.
The Group has no current revenues. The Group and the Company's cash balances are maintained in GBP Sterling
which is the functional and reporting currency of each Group company. Consequently, no formal policies have been
put in place to hedge the Group and Company's activities to the exposure to currency risk. It is the Group's policy to
ensure that individual Group entities enter transactions in their functional currency wherever possible. The Group
considers this minimises any foreign exchange exposure.
Management regularly monitor the currency profile and obtain informal advice to ensure that the cash balances are
held in currencies which minimise the impact on the results and position of the Group and the Company from foreign
exchange movements.
Capital management
The primary objective of the Group’s capital management is to maintain appropriate levels of funding to meet the
commitments of its forward programme of appraisal and development expenditure, and to safeguard the entity’s ability
to continue as a going concern and create shareholder value. The Director’s consider capital to include equity as
described in the Statement of Changes in Equity, and loan notes, as disclosed in Notes 14 and 15. Prior to 1 January
2016, the Group has been principally equity financed, reflecting the early stage and consequent relatively high risk of
its activities. During 2016, 2017 and 2018 the Group made drawings of £30.70 million against its London Oil & Gas
Limited loan facilities.
Borrowing facilities
The Group had £34.03 million of borrowings outstanding at 31 December 2018 (2017 - £13.00 million) including accrued
interest. It had in place further undrawn debt on the London Oil & Gas Limited facilities of a total £7.85 million excluding
accrued interest, at that date. A further £3.925 million was drawn in January 2019 and £3.925 million outstanding
remains.
Hedges
The Group did not hold any hedge instruments at the reporting date.
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
21 Financial commitments and contingent liabilities
The Group has contracted capital expenditure in the current period as part of the appraisal and development work
programmes for the licences in which it participates:
Authorised but not contracted
Contracted
2018
£000
2017
£000
-
1,287
_________
7,560
1,358
_________
1,287
_________
8,918
_________
All 2018 contracted amounts relate to contracted UKCS Licence Fee and associated OGA Levy payments (estimate)
together with contracted service awards to suppliers procured for the development of the Group’s SNS assets (Harvey
well long lead items, project personnel and offshore engineering duty holder commitments). There are no further
authorised amounts, at 31 December 2018, as the Group awaits the outcome of discussions and negotiations on Group
fund raising and refinancing.
All 2017 capital commitments, in addition to contracted UKCS Licence Fee and associated OGA Levy payments, were
owing to 2018 activities committed at 31 December 2017 in conjunction with the Group's participation in its UK North
Sea operations.
Skipper:
As detailed in Note 24, Subsequent Events, the Skipper licence P1609 was relinquished in February 2019, discharging
all contingent liabilities at that date.
Thames Pipeline:
Security in the sum of £0.50 million, the Initial Thames Decommissioning Pipeline Security Amount, was provided on
completion of the Thames Pipeline SPA in April 2018.
Further security in the sum of £2.50 million, the Thames Decommissioning Pipeline Security Amount, is to be provided
on the earlier of:
• one month after the variation issued by the OGA to the Pipeline Works Authorisation to allow for the tie-in of
one or more of the Group’s fields; or
• at the date of sale or alternative use of the Thames Pipeline
Cross-Guarantees:
The Company acts as guarantor to its subsidiary IOG North Sea Limited and its facilities with LOG. These cross
guarantees are considered insurance contracts in accordance with IFRS4.
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
22 Related party transactions
Details of directors’ and key management personnel remuneration are provided in Note 4.
Mark Hughes, COO, acquired 178,000 ordinary shares of 1p each in the capital of the Company and is the current
holder of these shares at 31 December 2018. Mark is also the current holder of 1,062,417 share options at 31 December
2018; these were also acquired during the year.
South Riding Consultancy Limited (‘SRCL’) of which Martin Ruscoe is a director acquired a further 65,067 share options
(2017: 113,254) and exercised nil share options (2017: 148,113) during the year. SRCL is the current holder of 148,113
shares and 109,766 share options as at 31 December 2018.
Details of loans and interest charged by LOG are detailed in Notes 14 and 15. The relevant loans were issued to both
IOG North Sea Limited and the Company.
23 Notes supporting statements of cash flows
Details of significant non-cash transactions
Equity consideration for settlement of liabilities
Group – Loans and borrowings
At 1 January 2017
Drawdowns (Repayments)
Effects of foreign exchange
Debt converted into equity
Debt converted into current liability
Amortisation of finance fees
Interest accruing in period
At 31 December 2017
2018
£000
-
2017
£000
1,982
Current
loans and
borrowings
£000
Non-current
loans and
borrowings
£000
Total
loans and
borrowings
£000
4,076
(2,019)
(15)
(1,750)
(527)
-
235
-
4,733
6,372
-
-
-
411
878
8,809
4,353
(15)
(1,750)
(527)
411
1,113
12,394
12,394
Of the interest accruing in the period, £22k was capitalised to D&P assets, leaving £1.09 million expensed to the
Statement of Comprehensive Income (Note 5).
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
23 Notes supporting statements of cash flows (continued)
Group – Loans and borrowings
At 1 January 2018
Drawdowns (Repayments)
Debt converted into current liability
Issue of warrants and finance fees
Amortisation of finance fees
Interest accruing in period
Current
loans and
borrowings
£000
Non-current
loans and
borrowings
£000
Total
loans and
borrowings
£000
-
-
6,934
-
-
-
12,394
18,787
(6,934)
(4,225)
617
2,245
12,394
18,787
-
(4,225)
617
2,245
29,818
At 31 December 2018
6,934
22,884
Of the interest accruing in the period, £752k was capitalised to D&P and Pipeline assets, leaving £1.49 million expensed
to the Statement of Comprehensive Income (Note 5).
Company – Loans and borrowings
At 1 January 2018
Drawdowns (Repayments)
Issue of warrants and finance fees
Amortisation of finance fees
Interest accruing in period
At 31 December 2018
Current
loans and
borrowings
£000
Non-current
loans and
borrowings
£000
Total
loans and
borrowings
£000
-
-
-
-
-
-
-
17,150
(4,224)
314
814
-
17,150
(4,224)
314
814
14,054
14,054
The Company was not subject to loans and borrowings in 2017.
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NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2018 (CONT’D)
24 Subsequent events
The key events after 31 December 2018 are as follows:
Fiona MacAulay was appointed non-executive Chair effective 1 January 2019.
Robin Storey was appointed General Counsel and Company Secretary on 9 January 2019.
Esa Ikaheimonen was appointed Non-Executive Director and Chair of the Audit Committee on 14 March 2019.
On 4 January 2019, it was announced that the Financial Conduct Authority (‘FCA’) was investigating the affairs of LCAF.
LCAF was subsequently put into administration during February 2019. Furthermore, LOG entered administration on 19
March 2019. The Company has engaged with LOG and LCAF administrators who have agreed to restructure the LOG
loans and have stated publicly that they will support IOG and the LOG/LCAF administration process will have no impact
on the Company’s business.
The Skipper licence, P1609, was formally relinquished on 11 February 2019, as determined by the OGA.
The Company announced on 25 February 2019 that it had initiated a focused farm-out process with a carefully selected
shortlist of motivated and well-funded potential farm-in partners.
The Company announced on 5 March 2019 that it had received and promptly rejected an unsolicited pre-conditional
proposal from RockRose Energy plc (‘RockRose’) in respect of a possible cash offer for the entire issued share capital
of the Company at a price of 20 pence per Company share. Subsequently on 25 March 2019, the Company announced
that RockRose had approached the joint administrators of LOG to acquire the entire debt and accrued interest due to
LOG from the Company for the sum of £40 million in cash. The Board concluded to reject the proposal unequivocally
and continue to state that this subsequent offer is a further transparent attempt by RockRose to deny both LOG’s and
LCAF’s creditors, and by extension to LCAF’s mini-bond holders, of fundamental value, seeking instead to reserve that
value for the benefit of RockRose and those directly associated with RockRose. RockRose withdrew their proposal on
1 April 2019.
The Company announced on 1 April 2019 that it had conditionally placed 165,795,050 new ordinary shares of £0.01
each in the capital of the Company by way of a placing at a price of 10 pence per Ordinary Share to raise gross proceeds
of approximately £16.6 million. In addition, a further proposed issue of 3,250,000 new Ordinary Shares by way of a
subscription at a price of 10 pence per Ordinary Share by certain directors and key executives of the Company.
Furthermore, the Company announced that it intends to launch an open offer to shareholders to raise approximately £2
million through the issue of approximately 20,128,580 new Ordinary Shares, also at an issue price of 10 pence per
share. This Fundraising is conditional, inter alia, upon the approval of shareholders at a general meeting of the Company
that will take place on or around 23 April 2019 and the admission of the relevant new Ordinary Shares to London AIM.
The Company announced on 1 April 2019, that concurrent to the Fundraising announcement above, the Company has
restructured its debt with LOG (in administration) by rescheduling by twelve months, initially to January 2020, an amount
of £7.1 million of debt service due to LOG, the conversion of £1.64 million in interest due from LOG’s existing convertible
debt into 20,497,204 new Ordinary Shares and a one year maturity extension to existing warrants being those
13,277,310 warrants which were granted by the Company in December 2015.
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Independent Oil & Gas plc
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INFORMATION & ADVISERS
INFORMATION AND ADVISERS
Country of incorporation of parent company
United Kingdom
Legal form
Public limited company with share capital
Directors
Fiona MacAulay
Andrew Hockey
Mark Hughes
Rt. Hon. Charles Hendry
Martin Ruscoe
Esa Ikaheimonen
General Counsel and Company Secretary
Robin Storey
Registered office
60 Gracechurch Street
London EC3V 0HR
Company registered number
07434350
Auditors
BDO LLP
55 Baker Street,
London W1U 7EU
Legal advisers
Fieldfisher LLP
Riverbank House
2 Swan Lane
London EC4R 3TT
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Independent Oil & Gas plc
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■ Registered Address
6th Floor
60 Gracechurch Street
London EC3V 0HR
■ Office
10 Arthur Street
London EC4R 9AY
■ Contact
+44 (0)20 3879 0510
www.independentoilandgas.com
ANNUAL REPORT & ACCOUNTS 2018
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