NEPTUNE ENERGY ANNUAL REPORT AND ACCOUNTS 2018 · Neptune Energy Annual Report and Accounts 2018 An international independent gas and oil exploration and production company, with

NEPTUNE ENERGY ANNUAL REPORT AND ACCOUNTS 2018

Annual Report and Accounts 2018Neptune Energy

An international independent gas and oil exploration and production company, with a regional focus on the North Sea, North Africa and the Asia Pacific region. Our diverse portfolio, agility and deep industry expertise offers multiple growth opportunities, both organic and through potential acquisition.

The North Sea is our core region where we have a strong operating platform. Our Gjøa and Cygnus assets in Norway and the UK, together with our strong presence in the Netherlands, are driving our current success, with great oppportunities to enhance further value. Germany provides a leading onshore position and access to material upside. Meanwhile, North Africa offers great potential for volume growth and is a key supplier to European markets. Our presence in Asia Pacific is fuelled by fast-growing gas demand and a well-established exploration and production business environment. Discover more in our Operational overview starting on page 14.

More information

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overnanceFinancial statem

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Strategic reportCompany at a glance 2Executive Chairman’s message 4Chief Executive Officer’s message 5Senior management 6Vision 8Strategic investors 9Risk management 10Corporate responsibility 12Operational overview 14

Europe 18North Africa 26Asia Pacific 28

Financial review 30

GovernanceCorporate governance and Directors’ report 34

Financial statementsIndependent auditor’s report 36Consolidated income statement 38Consolidated statement of comprehensive income 38Consolidated statement of financial position 39Consolidated statement of changes in equity 41Consolidated cash flow statement 42Notes to the consolidated financial statements 44 Supplementary information Gas and oil – unaudited 86 General information, forward looking statements, alternative performance measures 87 Get in touch 88

Except as the context otherwise indicates, Neptune or Neptune Energy, Group, we, us, and our, refers to the group of companies comprising Neptune Energy Group Midco Limited (the Company) and its consolidated subsidiaries and equity accounted investments. EPI refers to the business of ENGIE E&P International S.A. (now renamed Neptune Energy International S.A.) and its direct or indirect subsidiaries. The direct and ultimate parent undertaking is Neptune Energy Group Limited (NEGL). NEGL owns 100 per cent of the share capital of the Company. Please see page 87 for further general information.

Except as otherwise noted, the figures in this report are stated in US dollars or euros. All references to dollars or $ are to the US currency. We use adjusted profit measures, which exclude the impact of exceptional items and remeasurements. These are used by management to assess the underlying performance of the business.

CONTENTS

Neptune Energy Annual Report and Accounts 2018

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COMPANY AT A GLANCEOUR KEY MEASURES 2018

EuropeProduction

kboepd2P reserves

mmboe

Norway 77.8 348

Netherlands 28.3 38

UK 17.1 58

Germany 13.0 55

North AfricaProduction

kboepd2P reserves

mmboe

Algeria and Egypt 4.3 85

Asia PacificProduction

kboepd2P reserves

mmboe

Indonesia and Australia 21.3 53

Total 2018 Performance

* 2P numbers do not add up to 638 due to rounding differences

Business

Total headcount Shareholding in pipelines %

% of assets operated Number of licences

1,929 ~18/15 ~52 ~260NGT/NOGAT as at December 2018

Operations

Production kboepd 2P reserves Opex/boe % reserves replacement ratio

162 638 10.2 244mmboe of production

Financial

EBITDAX $m Cash flow $m Net profit $m Average realised prices

1,884 1,219 262 69.6/7.9from operations after tax, before acquisition related expenses

Oil $/bbl - Gas $/mcf

Climate and Clean Air CoalitionOur support and participation.

More information p23

Our commitment to diversity and equalityCreating a high-performing workplace and innovative business.


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Production

72% Gas 28% Oil

Revenue

48% Gas (including oil linked) 52% Oil

Business

Total headcount Shareholding in pipelines %

% of assets operated Number of licences

1,929 ~18/15 ~52 ~260NGT/NOGAT as at December 2018

Operations

Production kboepd 2P reserves Opex/boe % reserves replacement ratio

162 638 10.2 244mmboe of production

Financial

EBITDAX $m Cash flow $m Net profit $m Average realised prices

1,884 1,219 262 69.6/7.9from operations after tax, before acquisition related expenses

Oil $/bbl - Gas $/mcf

Safety culture programmeA report from Norway.



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EXECUTIVE CHAIRMAN’S MESSAGE BUILT ON DISTINCT PRINCIPLES

In creating Neptune Energy, our vision was to build a new type of international exploration and production (E&P)company; one that offered investors a distinct and diverse portfolio, engineered for growth and strong, sustainable returns.

To achieve that, we created Neptune based purposefully on three founding principles.

First, we will aim to maintain a production profile that is weighted more towards gas than oil. While we aim to strike the right balance to ensure growth through the cycle, we believe that gas offers investors a differentiated long-term offering, plays an important global role in the transition to lower carbon energy use and provides us with a natural hedge against fluctuations in oil prices.

Second, our portfolio will be geographically diverse, long-life and at scale. Not only does this ensure we spread risk through the cycle, but it also means we are able to access different commodity market prices, spread our geographic risk and provide greater optionality.

Third, we will have a strong balance sheet anchored by world-class investors, enabling us to pursue both organic and inorganic growth opportunities for value. This enables robust and low-cost production growth, good reserve replacement and strong cash flow accretion, to support both current returns and future growth.

We have a long-term view: short-term gains will not be at the expense of stable and sustainable growth through the cycle. We will act decisively but never with complacency. Health, safety and the environment (HSE) is central to every decision we make.

I would like to take this opportunity to thank my colleagues who have worked tirelessly to achieve so much in our first year. I would also like to thank our investors whose great support has helped establish Neptune Energy as one of Europe’s leading independent E&P companies.

With Jim at the helm, supported by a strong and experienced leadership team, the business has got off to a great start in its first year. I am confident about our delivery of an exciting growth agenda in 2019 and beyond.

Sam Laidlaw Executive Chairman

Health, safety and the environment is central to every decision we make.

A shared and relentless focus creates the right conditions to deliver strong, stable and sustainable returns.

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CHIEF EXECUTIVE OFFICER’S MESSAGE DELIVERING ABOVE EXPECTATIONS

2018 was a formative year for Neptune. Beginning with the completion of the EPI transaction, we set about supplementing it with the acquisitions of VNG Norge and the UK Seagull development project as well as the Isabella exploration prospect from Apache Corporation.

As underlying improvements in production management resulted in an increase in volumes at lower cost, we were well-placed to capture the value of higher commodity prices across the first three quarters of the year.

In the fourth quarter, oil and gas prices decoupled. While oil prices fell in the final three months of the year, gas prices were more resilient. Our gas-weighted production and hedging profile protected us from the full extent of the downside and left us in a stronger position.

Our performance demonstrated the resilience of the business and the strength of our portfolio – and it laid the foundations for a strong 2019; particularly important was the progress that we made with our health and safety performance.

Organic growth for Neptune means project delivery, exploration and development success and ultimately reserves replacement.

2019 has certainly started well with exploration licence awards in both Norway and Egypt, first gas in, at our Touat project in Algeria, the sanctioning of Seagull and development plans submitted for our Duva and P1 projects.

Increased exploration spend, project delivery and the increase of our reserves will doubtless be features of our performance during 2019. But equally important is the delivery of production targets, on budget and, most importantly, conveyed safely.

I am immensely proud of what the team has achieved in its first year and energised by Neptune’s growth potential. With a strong leadership team now in place, with an organisation consisting of highly-talented international staff, we are well-positioned to deliver our objective of being a leading international energy company.

James L House Chief Executive Officer

Our performance demonstrated the resilience of the business and the strength of our portfolio.

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Our strategic and operational progress in 2018 laid the foundations for growth into 2019 and beyond.


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SENIOR MANAGEMENTOUR DEPTH AND BREADTH OF EXPERIENCE

1. Sam Laidlaw Executive Chairman Company Director

2. Jim House Chief Executive Officer Company Director since 25 April 2018

3. Armand Lumens Chief Financial Officer Company Director since 7 January 2019

A,I (Chair), C, R (Chair) A, C, I, R A (Chair), C, I

4. Bruce Webb VP Operations

5. Mark Richardson VP Projects

6. Gro Haatvedt VP Exploration and Development

7. Andrea Guerra VP Reservoir Engineering

A, C, I

8. David Hemmings VP Business Development

9. Julian Regan-Mears Director of Corporate Affairs

10. Amanda Chilcott Group Human Resources Director

11. Kaveh Pourteymour Chief Information Officer

I C (Chair) C, R

12. Harald Knoebl General Secretary

13. Kick Sterkman Head of HSEQ

Committees

Audit and Risk Committee ACorporate Responsibility C CommitteeInvestment Committee IRemuneration & R Nomination Committee

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1. Sam is a founder of Neptune Energy and became its first Chairman in 2015. He is an experienced energy industry executive, with a strong international operational track record of more than 30 years in the oil and gas sector.Previously, Sam served as CEO of Centrica Plc, the integrated energy company engaged in sourcing, producing, trading and supplying energy and a range of related services.

Sam has also been a member of the UK Government’s Energy Advisory Panel, President of the UK Offshore Operators Association, a member of the Prime Minister’s Business Advisory Group, the Senior Director for the Department of Transport and a non-executive director of both HSBC Holdings Plc and Hanson Plc.

Sam is a non-executive director of Rio Tinto plc and Chairman of the National Centre for Universities and Business (NCUB).

2. Jim joined as CEO in January 2018. He has more than 30 years’ experience across the International E&P industry in North America, Europe, North Africa and the North Sea. Before taking up his role, he spent 26 years at Apache Corporation, most recently as the Senior Vice President responsible for Egypt, Mid-Continent US, Gulf Coast, Gulf of Mexico and International New Ventures.

Jim has served on the Upstream Committee of the American Petroleum Institute, the US Egypt Business Council within the US Chamber of Commerce, chaired the UK Oil Spill Prevention and Response Advisory Group (OSPRAG) plus the UK Production Efficiency Task Force while on the Council and Board of Oil and Gas UK.

Jim serves on the Texas A&M University Petroleum Engineering Department Industry Board and is a Lifetime Member of the Society of Petroleum Engineers.

3. Armand became CFO in December 2018. He has worked in the oil and gas sector for more than 20 years and provides Neptune with a deep knowledge and experience of energy and capital markets.Before joining the company, Armand was Group Chief Financial Officer at Louis Dreyfus Company. Prior to this he spent 24 years with Shell in various senior financial roles, including as Chief Financial Officer of Shell Trading and Supply.

Armand is also a non-executive director at Oryx Energies SA and V-Labs Virtual Reality.

4. Bruce was appointed as VP Operations in August 2018. He has more than 25 years’ international oil and gas experience. Previously he worked for DNO as COO based in Dubai leading businesses in Iraq, Oman, Tunisia and Somaliland.Prior to this, Bruce had a successful 23-year career with BP, starting as a graduate process engineer and on to leadership assignments in the North Sea, North America, Azerbaijan, Angola, as Global Director of Start-up and latterly as Vice President Operations and Head of Country for Algeria and Libya.

Bruce is a Fellow of the Institution of Chemical Engineers.

5. Mark joined Neptune in March 2018 having previously worked for Apache and BP. He has more than 25 years’ experience of the oil and gas sector and, before joining the industry, he was an officer with the Royal Engineers, serving with Commando Forces and specialising in military diving operations.Mark has served on the Subsea UK Board and the UK Engineering Construction Industry Training Board.

6. Gro joined Neptune in October 2018 with more than 30 years’ experience in the oil and gas sector. Previously, she was Senior Vice President for Exploration in Aker BP and held a variety of senior international roles in Equinor.

Gro is a member of the Magseis Fairfield Board and Geo Trade Organisation, GTO in Norway.

7. Andrea joined Neptune in August 2018 as VP Reservoir Engineering and has more than 18 years’ corporate international oil and gas sector experience.Previously she worked at Apache, with senior management responsibilities for their North Sea Reservoir Engineering division, South America New Ventures, Corporate International Planning, and Corporate Reserves and Economics.

8. David joined Neptune in July 2018 with more than 20 years’ experience in corporate finance in the oil and gas sector. David has a strong knowledge of capital markets in the energy sector, having advised oil majors, exploration and production companies and national oil companies on mergers and acquisition and debt and equity financing.Previously, he was a Managing Director in the energy and power advisory group at Rothschild.

9. Julian joined Neptune in September 2018 and is responsible for investor relations, public affairs, media relations, internal communications and corporate responsibility.Julian has more than 15 years’ experience leading international corporate communications functions, mostly in the energy and mining sectors, holding senior management positions with Centrica plc and The De Beers Group. Earlier in his career Julian led communications for Britvic plc’s listing.

10. Amanda joined Neptune in December 2018. With more than 20 years’ experience in human resources, she has worked with the Ford Motor Company, BP and Aggreko in a variety of global roles in the UK, continental Europe, China and the USA.

11. Kaveh joined as CIO in March 2019.Previously he was VP and CIO of Seadrill Management following senior leadership roles in BP’s Global Refining and International Businesses and with BOC Edwards.

Since 2008, he has held the position of Adjunct Professor at the business school of Imperial College London.

12. Harald joined Neptune as General Secretary in February 2018 from ENGIE, where he led governance, legal, ethics & compliance, audit and communication teams.With 20 years’ experience as a lawyer in the energy sector, mostly in upstream oil and gas, he holds a PhD in law and is a qualified attorney at the bar of Berlin, Germany.

13. Kick has 26 years of experience in upstream oil and gas, mostly in operational leadership roles, working for Expro, Clyde Petroleum, Wintershall and ENGIE. He joined Neptune as Head of HSEQ in February 2018 from ENGIE where he led Health, Safety, Environment, Quality and Security teams.

Directors who served during the year to December 2018

Yuling Lu resigned as Director of Midco on 15 February 2018 and Peter Thomas resigned on 7 January 2019.


VISIONEXCELLENCE AND EXPERTISE WILL FUEL OUR FUTUREOur vision is to become the leading international independent exploration and production company. To achieve this, we have defined a strategy that will build long-term shareholder value through sustainable growth. We will deliver this growth in value by:

• managing our assets and driving our production in a safe, efficient and sustainable manner;

• developing our exploration and development portfolio to ensure healthy reserves replacement;

• integrating past acquisitions successfully and high-grade our portfolio of activities;

• considering additional M&A activities, if these are value accretive; and

• driving an entrepreneurial culture without compromising integrity or safety.

Investor propositionOur vision is delivered by our unique investor proposition and our highly experienced team.

High quality, conventional, diversified and low-risk OECD-focused portfolio

Large-scale, long-life, and low-cost production profile

Proven operational capability across exploration, development and production

Well-positioned in gas markets and an important player in the energy transition

Significant cash flow generation, strong balance sheet and conservative risk management

Health, safety and environment (HSE) focus and experienced management

Well-invested asset base, with future capital expenditure flexibility and low decommissioning commitments

Our valuesWe are committed to continuous improvements in our HSE approach, reinforcing our already deeply-embedded safety culture, and harnessing digital and technological innovation to deliver even greater efficiencies.

These foundations are underpinned by the unrivalled knowledge and experience of our multinational workforce and are reinforced by our four core values:

ExcellenceWe strive to be the best, particularly in the areas of health and safety and carefully manage our environmental impact.

Accountability We take ownership of actions and results.

Integrity We have a commitment to ethical operations and respect every individual across every area of our business.

Teamwork Only by working together can we grow and only through partnership can we succeed.

Together, our values fuel a high-performance culture across the business. This culture centres on HSE, entrepreneurship, efficiency and value, attracting top E&P industry talent and creating an environment where our employees can flourish.

Our five principles of action1) Acting in accordance with

all applicable laws and regulations;

2) consolidating a culture of integrity;

3) behaving fairly and honestly;

4) respecting others; and

5) speaking up.

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STRATEGIC INVESTORSSTRONG SHAREHOLDER BASE

Neptune Energy was founded with strong backing from funds advised by three strategic investors: China Investment Corporation, The Carlyle Group and CVC Capital Partners.

In May 2018, our base was widened to include a range of bondholders, via a $550 million offering of 6⅝% senior notes in Neptune Energy Bondco plc, a wholly-owned subsidiary of NEGL. As part of the governance structure and processes, our three key investors

are represented on the Board of the holding company and meet at least four times a year. Strategic matters and financial reporting are discussed during Board meetings and various additional meetings between the shareholders and representatives of management.

Headquartered in Beijing, China Investment Corporation (CIC) was founded on 29 September 2007 as a wholly state-owned company incorporated in accord with China’s Company Law, with registered capital of US$200 billion. The company was established as a vehicle to diversify China’s foreign exchange holdings and seek maximum returns for its shareholders within acceptable risk tolerance. CIC is an

investor focused on the long-term development of its portfolio companies and is committed to being a prudent, professional and responsible institutional investor.

CIC invests in a wide range of financial products globally, including public equity, fixed income, alternative assets and cash and others. Public equity refers to equity investment in listed companies. Fixed income refers to bonds, including sovereign,

corporate, and agency bonds. Alternative assets include hedge funds, multi-asset investments, industry-wide direct investments, industry-wide private equity, resources/commodities, real estate and infrastructure. Cash and others includes cash, overnight deposits, and US Treasury bills.

Carlyle, through their Carlyle International Energy Partners fund, brings significant capital strength and wide experience in the E&P market, with several successful investments into E&P companies, including Neptune Energy, Assala Energy, Discover Exploration and Mazarine Energy.

The Carlyle Group is a global alternative asset manager headquartered in Washington DC, USA, with $174 billion of assets under

management across 306 investment vehicles.

Carlyle’s purpose is to invest wisely and create value on behalf of its investors, many of whom are public pension funds. Carlyle invests across four segments – Corporate Private Equity, Real Assets, Global Market Strategies and Investment Solutions – in Africa, Asia, Australia, Europe, the Middle East, North America and South America.

Carlyle has expertise in various industries including:

aerospace, defence and government services, consumer and retail, energy, financial services, healthcare, industrial, real estate, technology and business services, telecommunications and media, and transportation.

The Carlyle Group employs more than 1,550 people in 31 offices across six continents.

CVC Capital Partners, through their CVC Capital Partners Fund VI, brings over 30 years of investment experience and substantial financial strength, completing over 300 investments, including delivering complex corporate carve-outs.

CVC Capital Partners is one of the world’s leading private equity and investment advisory firms. Founded in 1981, CVC today has a

network of over 20 offices and more than 420 employees throughout Europe, Asia and the USA.

CVC manages capital on behalf of institutional, governmental and private investors worldwide. The capital of CVC’s investors is committed for 10 years or more to closed-end funds.

To date, CVC has secured commitments of over US$71 billion in funds from

this diverse and loyal investor base, completing over 300 investments in a wide range of industries and countries across the globe.

CVC invests in partnership with companies’ own management teams and assists in developing plans to create sustainable long-term value.

Risk management is integral to our investor proposition of creating an efficient independent E&P company.

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RISK MANAGEMENTPRESERVE AND PROTECT

The oil and gas sector and Neptune are exposed to a variety of risks and uncertainties, which are managed by means of enterprise risk management.

We use a management system of risk identification and deploy three levels of defence for risk mitigation. We are currently expanding the systematic use of these tools with the aim of further strengthening our governance in this area and standardising our framework of internal controls. For further information about our risks and uncertainites see note 21 on page 74.

In early 2019, we defined the terms of reference of a Corporate Responsibility Committee, including HSE, and an Audit and Risk Committee.

Our core oil and gas businesses expose us to a variety of political, economic and environmental risks, which could affect our ability to achieve our strategic objectives. However, if correctly identified and managed, these risks and uncertainties can also represent significant opportunities for growth.

Prices, exploration, development, production, projects and costs• Oil and gas prices and currencies are

volatile and our results of operations, cash flows, financial condition and access to capital could be affected. Our future success depends on our ability to find, develop or acquire additional reserves that are economically recoverable, which is dependent both on our exploration success and on oil and gas prices.

• Our exploration, development and production operations are subject to operational health, safety and environmental hazards and unforeseen interruptions, including drilling, exploration and production risks that may affect our ability to produce oil and gas.

• The level, quality and production volumes of our oil and gas reserves and resources could vary from reported reserves and resources if the assumptions, upon which the estimates of our oil and gas reserves and resources have been based, prove to be incorrect.

• Our development projects require future capital expenditures and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our oil and gas reserves.

• We may face unanticipated increased or incremental costs in connection with decommissioning obligations.

We use our expertise to develop know-how and technologies for the integration of all phases of the gas production chain including security, environmental protection and process efficiency.

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Competition, partners, staff, climate change, legislation and macro-economic factors• We carry out business in a highly

competitive industry and we may not always be able to keep pace with technological developments in our industry.

• We conduct some of our operations with commercial partners, which may increase the risk of delays, additional costs or the suspension or termination of the licences or the agreements that govern our assets.

• We depend on key members of management, independent experts, technical or operational service providers and on our ability to retain and hire such persons to effectively manage our growing business.

• Climate change and fossil fuel extraction related legislation may have a material effect on our industry.

• Our exploration and production operations are dependent on our compliance with obligations under licences, contracts and field development plans and on obtaining licences, approvals and permits from governmental authorities.

• Our future growth and performance also depend on our ability to integrate and realise the expected benefits of the acquisitions we initiated.

• We are affected by global macro-economic and financial conditions and certain countries in which we do business face political, economic, fiscal, legal, regulatory and social uncertainties which could adversely affect our business, prospects, financial condition and results of operations.

HSE risks are managed by a specific management system and by strictly adhering to laws, policies and procedures, as well as through insurance. Commodity price risk and exchange rates volatility are mitigated through continuous hedging. Counterparty and credit risk are limited by carefully selecting the companies we sell to and the suppliers and joint venture partners we work with. We aim to obtain operatorship in joint ventures and limit over-exposure to a single country.

The compliance, legal and internal audit functions aim to reduce compliance risks by monitoring and enforcing the adherence to laws, standards and procedures.

Together with human resources, the senior leadership team and the Board set the tone of the organisation by role-modelling behaviours and by recruiting staff with the right mindset to ensure compliance and a culture of integrity.

More information

For further discussion of our risks and uncertainties see note 21 on page 74.

Engagement sessions

30+with colleagues as we rolled out our Safety Culture programme

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Corporate responsibility is not just a policy for us; it’s a philosophy that is underpinned by the values and behaviours of each and every person who works for Neptune. It is about working safely and with care for each other and the environment. It is about building a sustainable business that can identify and transform environmental and societal problems into development opportunities. And it is about creating long-term value for all our stakeholders while limiting the consumption of natural resources.

Health and safetyWe take our duty of care to the people who work for us extremely seriously. We are embedding a safety culture across the business with zero tolerance for accidents, damage or harm to our people.

We believe that all incidents are preventable. Everyone at Neptune, from top to bottom, commits to our HSE policies and works collaboratively to ensure they are enforced.

Colleagues are expected to speak out if anyone’s safety is considered to be at risk and encouraged to regularly check that our robust health and safety standards are being upheld. In this way, we are continually strengthening our safety culture throughout every part of the organisation.

It is not only physical health that is an important consideration, but also mental health. We expect our staff and contractors to be mindful of each other’s wellbeing, ensuring individuals are well rested, fit and able to carry out the work they are responsible for.

In 2018, our performance continued to improve across all our operating countries and we further developed our Safety Culture project, which serves to reinforce safety basics and establish health, safety, security and environment (HSSE) objectives.

While this is a positive achievement, safety results can always be better. For that

CORPORATE RESPONSIBILITYHERE FOR GOOD

In every part of our business, we are committed to acting responsibly, safeguarding people, protecting the environment and making a positive contribution to society.

4.87 4.86 4.824.62

4.22

3.593.55

3.182.98

2.45 2.52 2.60

1.49 1.50 1.631.42 1.37

0.98 0.970.80

0.96 0.82 0.80 0.85

Man

hou

rs (m

illio

n)

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

TRIR

and

LTI

F

20

19

18

17

16

15

14

13

12

11

10

6.00

5.00

4.00

3.00

2.00

1.00

0.00

TRIR1

Target TRIR Neptune

IOGP2 TRIR

LTIF3

Target LTIF Neptune

IOGP LTIF

Man hours

1. Total recordable incident rate

2. The International Association of Oil & Gas Producers Global Average

3. Lost time injury frequency rate

Our health and safety track record

TRIR is a US measure of occupational safety and health, useful for comparing working conditions in workplaces and industries. LTIF is the number of lost time injuries occurring in a workplace in a 12-month period per one million hours worked.

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reason, we remain steadfastly focused on efforts to reduce incident probability to the absolute minimum levels that can be achieved.

EnvironmentWe apply the same philosophy of active commitment to caring for and protecting the environment. We are committed to environmentally-responsible operations, energy efficiency and the transition to a low carbon future.

Pollution prevention, reduction of natural resource consumption and emissions, and the reduction and recycling of waste are three of the ways we seek to minimise our impact on the environment.

We comply with environmental regulations in force both internationally and in the individual regions in which we operate. In some cases, we apply our own standards which are more stringent. We are committed to continuous improvement to achieve best practice management of environmental issues.

Managing energy consumption is a priority, addressing not only the issue of climate change but also that of the foreseeable depletion of some energy resources.

We devise and implement energy efficiency solutions. Gjøa, located in the northern North Sea, is the first floating platform operating with power from shore through a 100 km long submarine cable from Mongstad. Electrification of

the Gjøa field reduces CO2 emissions by 200,000 tons a year. This corresponds to the emissions from 100,000 cars.

The Q13a-A production platform in the North Sea, just off the coast of Scheveningen, is provided with electricity by a cable from a mainland facility instead of using a power generator offshore. This prevents the use of fossil resources and is more environmentally friendly. It saves approximately 14,000 tons of CO2 emissions per year.

In its Environmental Performance indicators report for 2017, the International Association of Oil & Gas Producers placed Neptune in the top quartile of performers. Nevertheless, we are always working to continually improve our record.

CommunitiesAt Neptune, we pride ourselves on being part of the community. That is why our relationships with the many and diverse local and regional communities in which we operate are an important part of our business.

Through these partnerships, we can better understand the needs of each community and the impacts our activities are likely to have. Working together with a wide range of local stakeholders, we are able to create appropriate sustainable development initiatives that reflect community priorities and focus on development.

Our people

We strive to treat everyone with fairness, respect and dignity and expect our partners and suppliers to act in a way that is consistent with our sense of fairness and equal opportunity.

Stakeholder engagement

We recognise the regulatory, societal and political framework of our activities and the growing scrutiny of the way we perform. The need for a transition to a low-carbon economy is a major driver for this. We therefore focus on gas as a low carbon fuel.

We work with all our stakeholders – including national, regional and local authorities, politicians, NGOs, knowledge institutions and business associations – to operate our activities safely and responsibly, and to make a positive and meaningful contribution to the energy transition.

Our commitment to diversity and equalityWe believe diversity and equal opportunities empower our business and our people. By championing both, we create a high-performing workplace and a more resilient and innovative business.

We value every one of our colleagues for the unique skills, abilities, creativity, and experience they bring to the business. Everyone directly contributes to our success and reputation. That is why we are committed to treating everyone with fairness, respect and dignity and expect our partners and suppliers to do the same.

It should be no surprise, then, that we have zero tolerance for any form of discrimination. Decisions related to recruitment, development and promotion are based on aptitude and ability. Factors such as age, gender, sexual orientation, marital status, race, colour, ethnic origin, religion or belief, disability, or political views play no part in our selection and recruitment process.

Our policy is that people with disabilities should be given fair consideration for all vacancies against the requirements for the role. Where possible, we make reasonable adjustments in job design and provide appropriate training for existing employees who become disabled.

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OPERATIONAL OVERVIEWPOSITIONED FOR GROWTH

Neptune’s financial and operational performance in 2018 was strong, reflecting increased production, reduced costs, higher average realised oil and gas prices and excellent reserves replacement.

Neptune’s financial and operational performance in 2018 was strong, reflecting increased production, reduced costs, higher average realised oil and gas prices and excellent reserves replacement for the asset base.

Having completed the acquisition of the worldwide oil and gas exploration business of ENGIE (EPI) on 15 February 2018, we made significant strategic progress during the year and are now firmly established as one of Europe’s leading independent exploration and production companies.

Neptune considers HSSE of primary importance. Continued improvement in HSSE has been achieved across the Group throughout the year with material reductions in both injury frequency rates and lost time injuries. Targets for further improvement have been set for 2019.

To achieve this we have raised awareness, strengthened our safety culture and improved our processes and reporting.

Despite being a transitional period, our operational performance in 2018 was strong, with production increasing to 161.8 kboepd and operating costs decreasing to $10.2/boe for the asset base. The production increase reflected a full 12-month contribution from the Jangkrik field (Neptune 33.33 per cent working interest) in Indonesia and improved efficiency across the Group.

The Group’s move to a country-led model provided greater focus and management oversight, enabling more rigorous production management and reporting, along with enhanced reservoir management. This approach helped improve production volume, but also availability, and will bring longer-term benefits across the portfolio.

Our goal is to deliver engineering and construction quality and production efficiency, while meeting our commercial, investment, environmental and safety targets and obligations.

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42 In September we completed the acquisition of VNG Norge AS, which added three producing fields, two development projects and 42 licences to our existing portfolio.

161.8Despite being a transitional period, Neptune’s operational performance in 2018 was strong, with production increasing to 161.8 kboepd for the asset base.

The work of our development engineers is essential for choosing the best technical and economic solution and for implementation of investment decisions.

These efficiency gains were supplemented with cost savings across the Group from standardisation of systems, organisational design improvements, process simplification, rigorous cost management and disciplined capital allocation. We have more to do to reduce costs further in some parts of the portfolio and we are implementing systematic programmes across the Group.

As operator of around half of Group production, Neptune has been able to drive operational improvements. Where we do not have operatorship, we have proactively engaged with our partners to identify growth opportunities and enhance performance.

Higher production and strong average oil and gas prices combined to drive post-tax operating cash flow to $1,156 million. EBITDAX increased to $1,884 million for

the 10 and a half month period, enabling the Group to announce a first year annual dividend of $380 million.

Neptune maintains a strong balance sheet, with net debt to EBITDAX standing at 0.84 times. Strong cash flow and the bond issuance in May 2018 resulted in total headroom, including undrawn debt facilities, of more than $1.1 billion at the end of 2018, providing the Group sufficient financial headroom to pursue value-accretive acquisitions.

We also maintain a conservative approach to financial risk management: we typically hedge at least 50 per cent of post-tax production in the first year, 30 per cent in the second year and 15 per cent in the third year. Hedging oil and gas price exposures in this way helps protect a significant portion of post-tax cashflow on a three-year rolling basis.

16

Annual Report and Accounts 2018Neptune Energy

While strong oil and gas prices during the first three quarters of the year boosted revenues from higher production, commodity prices were less supportive in the fourth quarter. During the period, oil prices fell by 35 per cent and natural gas prices, while more resilient, were 17 per cent lower. The Group’s asset mix and hedging policy provided some protection from these movements during this period.

Our strong balance sheet and robust level of liquidity enabled us to complete two strategic bolt-on acquisitions during the year. In September, we completed the acquisition of VNG Norge AS, which added five producing fields, two development projects and 42 licences to our existing portfolio.

In December, Neptune completed the acquisition of Apache’s 35 per cent working interest in the Seagull development and a 50 per cent working interest in the Isabella prospect, providing low-cost, near-term development in close proximity to existing infrastructure, as well as a material undrilled prospect in the Central North Sea.

Neptune’s portfolio also includes important organic growth opportunities, with projects under way representing significant future production growth over the next three years. Progress with these projects continued apace in 2018 with all key projects on track.

• The first of these, the Touat gas project in Algeria, is expected to come online by the end of the first half of 2019 and represents almost 75 kboepd at peak gross production. First gas into the plant was achieved in February 2019.

• In Norway, construction of the operated Fenja project also continued on track, with first hydrocarbons expected in Q1 2021. Start-up will follow the recommencement of production from the Njord and Hyme fields in Q4 2020 and first oil from the Bauge tie-back. Fenja is expected to add 13 kboepd of net production and the Njord, Hyme and Bauge fields are expected to contribute 22 kboepd.

• Since year end, the Neptune operated Duva and Gjøa P1 projects in Norway and the Seagull development in the UK have been sanctioned. In aggregate, we anticipate that Duva and Gjøa P1 will provide an additional 16 kboepd of net production, with start-up expected in late 2020. The Seagull project is expected to add 17 kboepd from first oil in Q4 2021.

Exploration is another key element of our organic growth strategy. In 2018, Neptune drilled eight exploration and appraisal wells, resulting in three discoveries. The most notable of these was the Sigrun field (Neptune 25 per cent working interest). Exploration drilling expenditure in 2019 will increase markedly, with seven wells planned, including material wells in Indonesia, the UK and Germany.

The year 2018 saw a thorough review of the Group’s 2P reserve base, audited by an independent reservoir consultant. At the end of 2017, 2P reserves were estimated at 555 mmboe. Neptune now estimates its 2P reserve base to be 638 mmboe – significantly ahead of expectations at the time of acquisition of EPI. On a forward looking basis, our reserves over production ratio is now 11 years (from 9.6 years previously).

Neptune strengthened its management team significantly throughout 2018, with the appointment of a new CFO and key managers to lead operations, technical, projects and Group functions.

The Group’s strong financial and operating performance in 2018, coupled with its good strategic progress, leaves it well-positioned for growth as the sector continues to present opportunities for consolidation.

Operational overview continued

Daily average production

Dry gas production (kboepd)

Gas production for sale as LNG (kboepd)

Liquid production (kbpd)

Total production (kboepd)

2018

2018

2018

2018

82.0

34.2

45.6

161.8

2017

2017

2017

2017

Neptune Energy

Pro forma information

87.0

18.8

48.5

154.3

1) Daily average production over the period 15 February to 31 December

2) Liquid includes oil and condensate and other natural gas liquids

17

Strategic reportG


ents

ProductionNeptune produced 161.8 kboepd in the period to 31 December 2018. On a pro forma basis, production would have been 159.1 kboepd, a 3.1 per cent increase on the equivalent period in 2017.

The increase in production was due largely to the first full 12-month contribution from Jangkrik in Indonesia. Production from Cygnus in the UK also contributed to the increase, as the Group benefited in the first half of the year from the debottlenecking that was carried out in 2017, while key fields in Norway also performed strongly.

Since our acquisition of EPI, we have taken a much more rigorous approach to production management, providing management with greater levels of oversight across the portfolio, particularly reservoir management and production reporting.

For the Group, the reserves replacement ratio for 2018 was 244 per cent or 141 per cent on an underlying organic basis. All our reserve estimates are externally audited by an independent reserve auditor.

OutlookIn 2019, we anticipate that production will average 155-160 kboepd reflecting natural decline in the first half of the year and a contribution from field development activity in the second half. This is expected to include start-up of Touat by mid-year and three infill wells at Fram in Q4. Group production in the final quarter of 2019 is expected to reach new record levels and we anticipate further growth to come as the Seagull, Duva, Gjøa P1, Fenja and Njord developments come on stream over the next three years.

While responsibility and accountability for production lies with the country teams, improved reporting processes have helped improve production availability. More effective reservoir management is also having a positive impact, helping to slow natural decline in Norway and the Netherlands.

Reserves (mmboe)We delivered strong reserves growth in 2018, ending the year with proved plus probable reserves (2P) of 638 mmboe. The increase was due to positive revisions at Cygnus and Gudrun, extensions at Duva, Fram, Gjøa P1 and Snøhvit and the acquisitions of VNG Norge and the Seagull project. Reflecting this, Norway and the UK achieved very strong reserves growth in the year. We had reserve downgrades in Indonesia and Germany.

2P reserves

031 Dec 17

555

59

79

(57)

638

Acquisitions Revisions, extensions and discoveries

Production 31 Dec 18

200

100

600

500

400

300

700

800

Start/end reserves

Increase

Decrease

18


EUROPENORWAY

Norway continues to be the largest contributor to Neptune’s global production portfolio, representing almost 50 per cent of the Group’s volume. In the period to 31 December 2018, we produced 77.8 kboepd in Norway. On a pro forma basis, this was 4.4 per cent lower than the same period in 2017, but higher than expected. This strong performance was due largely to better than expected reservoir performance

from Gudrun, Gjøa and Fram. In addition, Gjøa, Gudrun and Snøhvit uptime has been higher than assumed. The Gjøa field commenced natural decline in mid-2018 and operations are expected to be continuously optimised to mitigate decline. The Gjøa facilities will become an important host platform for Nova, Duva, Gjøa P1, extending the field life beyond 2030. In the final quarter of the year, the VNG Norge acquisition contributed approximately 3.9 kboepd.

From late 2020, Norway is expected to deliver significant production growth with the operated Fenja, Duva and Gjøa P1 projects scheduled to add 29 kboepd and the non-operated Njord project adding 22 kboepd.

In 2018, operating costs averaged $7/boe. During the period, there was a focus on further cost improvement measures. This discipline is expected to generate further savings in 2019, with operational, logistics and transportation savings identified.

Reserves and resourcesNeptune had 348 mmboe of proved plus probable (2P) net reserves in Norway at the end of 2018. The 2P reserves replacement ratio for 2018 in Norway

Norway continues to be the largest contributor to Neptune’s global production portfolio, representing almost 50 per cent of the Group’s volume.

1211

109

87

65

4

32

1

1. Snøhvit PO2. Njord Area PO3. Draugen PO4. Fenja D5. P1 D6. Duva D7. Gjøa O8. Nova D9. Fram PO10. Brage PO11. Gudrun PO12. Ivar Aasen PO

ProducingRedevelopment

ProducingDevelopmentDevelopmentDevelopment

ProducingDevelopment

ProducingProducingProducingProducing

O Operated PO Partner operatedD Development

Assets

19

Strategic reportG


ents

was 500 per cent, including significant volumes added from the maturation of contingent resources at Duva, Fram, Gjøa, Snøhvit and revisions at Gudrun. The VNG Norge acquisition added 46 mmboe of reserves.

DevelopmentIn 2018, Neptune invested heavily in Norway spending around $200 million on development activities, including the Njord, Fenja and Snøhvit projects. In 2019, we expect to increase development spending significantly to over $450 million. Investment will include the Njord, Fenja and Duva/Gjøa P1 Projects and development drilling on Askeladd, Bauge, Brage, Fram, Gudrun and Ivar Aasen.

During the past year, spending was focused predominantly on the Njord redevelopment project. In 2018, the Njord B floating storage unit was transferred to dry dock at the Aibel yard and the Njord A heavy lift campaign commenced. Njord will remain an important area of spending in 2019. Planning for production start-up will also commence ahead of the recommencement of production in Q4 2020.

Execution of the operated Fenja project also made good progress in 2018 and remains on schedule and budget. During the year, the modules and subsea production system were fabricated and structural elements were installed on Njord A. In 2019, the Fenja modules will be installed on Njord A and marine installation activities is expected to commence. Drilling will start in 2020.

Since year end, our operated Duva and Gjøa P1 projects have been sanctioned as a cost-effective, fast-track subsea tie-back to the Neptune operated Gjøa facilities. Engineering, procurement, construction, installation and commissioning (EPCIC) contracts for the subsea production system, subsea/umbilicals/risers/flowlines and Topside will be awarded in the near term and in late 2019, Neptune will commence drilling ahead of the subsea campaign starting in early 2020. First oil is planned for late 2020 or early 2021; this is 18 months earlier than previously projected and reflects the Group’s focus on delivering growth and value. Total recoverable resources are estimated to be 120 mmboe, with the Duva field expected to achieve peak gross production of 30 kboepd and the Gjøa P1 field 24 kboepd.

The Askeladd development was sanctioned in March 2018 and remains on schedule and budget for first production by the end of 2020. Capacity testing will also be carried out in 2019 and may support higher future production.

ExplorationIn 2018, exploration expenditure in Norway totalled $66 million, representing nearly two-thirds of the Group’s total exploration spending in the year. During the period, the Group made significant investments in seismic acquisition, as well as participating in the drilling of two exploration wells. In August, we announced the success of the Sigrun appraisal well (Neptune 25 per cent working interest). The commercial potential of this discovery will be evaluated in 2019. The non-operated Silfari well was unsuccessful.

In 2019, we expect to continue to have an active exploration programme, with the Sigrun East (Neptune 25 per cent working interest) and Echino South (Neptune 15 per cent working interest) wells both due to be drilled late in the year. We are taking a proactive approach to licence decisions to support reserves replacement in Norway and are maturing a number of high impact prospects for drilling in 2020 and beyond.

LicencesIn early 2019, Neptune was awarded nine exploration licences in mature areas of the Norwegian Continental Shelf, including four as operator. The licences strengthen our position as operator in and around our core areas, including the greater Njord-Fenja area, the Gjøa-Duva area and in the Central Graben. The new licences have 3D seismic acquisition and reprocessing commitments, with drill or drop decisions in 2021. We see considerable exploration potential in our acreage in Norway and anticipate drilling activity to increase in future as we target material organic growth opportunities.

1211

109

87

65

4

32

1


Neptune Energy Norway

Gas production (kboepd)

Gas production for sale as LNG (kboepd)



2018

2018

2018

2018

28.9

13.7

35.2

77.8

2017

2017

2017

2017

30.0

11.5

37.2

78.7

Neptune Energy


Headcount

4282P reserves mmboe

348 Development spend in 2018 $m

~200

1) Includes impact of EPI for 320 days and VNG for 92 days from 1 October 2018

20


10

9

87

6

543

2

1

1

1

EUROPENETHERLANDS

Production from the Netherlands was in line with expectations in 2018, contributing 28.3 kboepd to Group production. During the period, good field performance from G14, E17, L10/K12 and K2 was offset by lower production from L5a-D and third-party deferments.

Production from the Netherlands was in line with expectations in 2018, contributing 28.3 kboepd to Group production.

Assets

The Q13 field was also shut-in for an extended period due to the unavailability of the P15 facilities. Although the Netherlands offshore is relatively mature, our production performance in 2019 will benefit from infill drilling in the second half of the year.

During 2018, operating costs per barrel were substantially below budget at $12/boe, reflecting savings achieved in offshore transportation costs and some deferral of expenditure. These savings, along with a slightly higher sales volume, helped underlying earnings for our Netherlands business grow compared with 2017.

In 2019, underlying operating costs for our assets in the Netherlands are expected to fall in absolute terms, but will be partially offset by the expected settlement of historical operating costs related to the unitisation of E17. The expected reduction in opex will be driven by new management systems implemented in late 2018, which will enable us to run our assets more effectively and efficiently.

1. FLQ O2. G O3. D12-A PO4. D15 O5. F16-A PO6. K6-D PO7. K12-B O8. L10 O9. Noordgastransport I10. NOGAT I

O OperatedPO Partner operatedI Infrastructure pipeline

21

Strategic reportG


ents

10

9

87

6

543

2

1

1

1

Reserves and resourcesProved plus probable (2P) net reserves in the Netherlands at the end of 2018 amounted to 38 mmboe.

DevelopmentIn 2018, Neptune brought three new wells on stream and completed several well interventions. The L5a-D platform started-up in February. Facility modifications were also carried out to meet NOx (nitrogen oxide) legislation with these projects due to be completed in 2019.

In 2019, two new development wells are planned. Several other infill opportunities will be matured in 2019 as the Group works to extend the life of existing facilities by focusing on high value incremental projects. Detailed engineering will also begin for the F17a-A oil development.

Decommissioning activity in the Netherlands continues on the L10 C, D and G platforms with preparation work performed in 2018 and the removal of the jackets and topsides planned in 2019.

ExplorationExploration expenditure in the Netherlands was $6 million in 2018. Neptune participated in three wells, which resulted in two small gas discoveries (Ziegler and Andalusite). The F17-CK3 well was unsuccessful. In 2019, we expect to increase our exploration expenditure, with several new prospects being developed.

Neptune Energy Netherlands

The Neptune Energy portfolio includes ~40 licences in the Netherlands.




2018

2018

2018

26.1

2.2

28.3

2017

2017

2017

29.0

3.3

32.3

Neptune Energy


Headcount


38Licences

~40


22


EUROPEUK

In the UK, production from the Group’s assets averaged 17.1 kboepd in 2018. While production in 2018 was impacted by third-party restrictions at Cygnus, which is likely to continue in 2019, volumes are expected to be higher than those achieved in the second half of 2018.

Production from the Cygnus field is currently constrained to 250 mmcfpd due to compressor stability issues on

the third-party Trent platform. This is significantly below the 320 mmcfpd rate possible following completion of the Bacton debottlenecking project.

During 2018, we achieved a substantial reduction in operating costs in the UK, with opex per barrel falling substantially to $7/boe. Operating costs were reduced at our non-operated assets, which have now largely ceased production. Combined with strong realisations, we achieved good growth in earnings from our UK operations in 2018. Looking forward, we are focused on improving our culture of cost control through greater financial awareness, ownership and innovation.

Reserves and resourcesIn 2018, we achieved a material 16 mmboe increase in proved plus probable (2P) net reserves in the UK to 58 mmboe. The acquisition of the Seagull field added 13 mmboe and there were positive revisions to Cygnus reserves following the Bravo well results. The proved plus probable reserves replacement ratio for 2018 was 350 per cent.

In the UK, production from the Group’s assets averaged 17.1 kboepd in 2018.

65

4

3

2

1

Assets

1. Seagull D2. Isabella E3. Ossian Darach E4. Pegasus D5. Cygnus O6. Cygnus Gas

Compression O

O OperatedD DevelopedE Exploration

23

Strategic reportG


ents

DevelopmentWe spent $36 million on development activities in 2018, with almost all of this attributed to the Cygnus field. During the year, corrosion failure of the vent line resulted in several unplanned shutdowns. The corroded sections have since been replaced, with the entire line due to be replaced by corrosion resistant pipe in the planned August 2019 shutdown. In 2019, a compression project is also due to be completed, along with two infill wells. Additional infill opportunities are being matured for drilling in 2020.

In March 2019, the Neptune operated Seagull development was sanctioned. The high pressure, high temperature (HPHT) field will be developed as a subsea tieback to the ETAP central processing facility (CPF) platform, with first production due in Q4 2021. Capex spending in 2019 is forecast to increase modestly reflecting the start-up of development activity on the Seagull project.

In the UK, decommissioning planning continues for the scopes on Minke, which is located in both the UK and Netherlands sectors, as well as Juliet. In 2019, the Juliet and Minke pipelines will be flushed.

ExplorationIn 2018, Neptune spent $14 million on exploration activities in the UK, with a similar level of expenditure planned in 2019. During the past year, Neptune drilled the unsuccessful FB9 well north-east of Cygnus. Additional exploration opportunities are being matured in the Greater Cygnus Area.

In 2019, two exploration wells are planned. One in the Southern North Sea and the other a high-potential HPHT Central North Sea prospect to be confirmed.

CygnusClimate and Clean Air Coalition

We are a member of the Climate and Clean Air Coalition (CCAC) Oil & Gas Methane Partnership. Its aim is to step up the efforts to reduce methane emissions to the atmosphere. The CCAC O&G Methane partnership seeks to achieve expanded and accelerated near-term reductions in methane emissions from oil and gas operations globally. Gjøa in the Norwegian North Sea and Cygnus in the UK sector are participating in the initial phase of the programme.

Neptune Energy UK

65

4

3

2

1

The International Energy Agency has identified minimising methane emissions from upstream oil and gas production as one of the five key global mitigation opportunities to reduce greenhouse gas emissions by 2020.




2018

2018

2018

16.7

0.4

17.1

2017

2017

2017

17.6

0.4

18.0

Neptune Energy


Headcount (excluding head office)


58Licences

~25


24


EUROPEGERMANY

In 2018, production from Germany was resilient, averaging 13.0 kboepd during the year, reflecting good production management.

During the period, operating costs, excluding royalties, were $22/boe. For 2019, we are targeting a 10 per cent reduction in operating costs per barrel. A strong operational focus has been

put on automation projects across the portfolio. We are also implementing an organisational restructuring and are taking measures to contain and reduce operating costs and G&A, which will improve the competitiveness of our German operations in the future.

Reserves and resourcesIn Germany, Neptune has proved plus probable (2P) net reserves of 55 mmboe. Reserves were reduced due to a technical revision for the Römerberg field.

DevelopmentIn 2018, we continued to invest across our portfolio in Germany. The Rühlermoor sidetrack infill campaign was completed successfully during the period and further opportunities have been identified to slow natural field decline.

In South Germany, drilling challenges delayed completion of the Römerberg 8 well and testing is now anticipated in Q2 2019. A number of other opportunities to enhance production from the Römerberg field are planned, including the recompletion of the Römerberg 5 well.

In 2018, production from Germany was resilient, averaging 13.0 kboepd during the year, reflecting good production management.

4

3

21

Assets1. West Germany We operate nine gas fields and six oil fields in the region.

2. West Germany We participate in several partner-operated gas fields working with DEA, ExxonMobil and Wintershall. We also work with ExxonMobil on several oil production sites.

3. Central and Eastern Germany We operate seven gas fields and seven oil fields with 199 wells currently being active.

4. Rhine Valley We work with Palatina GeoCon at two operating sites.

1. Western Germany O2. Western Germany PO3. Central and

Eastern Germany O4. Rhine Valley O

O OperatedPO Partner operated

25

Strategic reportG


ents

In our West German operations, production will be maintained in 2019 through infill drilling and an ongoing well intervention. The Adorf Z15 gas well is scheduled for Q4 2019 and well pad construction started earlier in the year.

In addition to drilling and development activities, Neptune continues to invest in responsible reclamation and restoration of some older sites and fields in the portfolio.

ExplorationIn 2019, the Group’s exploration activity in Germany will increase with around $7 million budgeted. This reflects mainly the drilling of the Schwegenheim exploration well (Neptune 50 per cent working interest). Well pad construction for Schwegenheim has already started ahead of planned drilling in Q2/Q3. Neptune holds a number of highly prospective exploration licences in the Rhine Valley and the outcome of this well is important in understanding the potential of the region, where little exploration has occurred in recent years.

Site restorationNeptune Energy Germany: Fields become fields again

On average, a reservoir is depleted after 20 to 30 years.

Upon abandonment, the production facilities are dismantled and the drilling site is restored to its original condition.

The well is safely plugged and the former production locations are covered with topsoil.

The land can then be used for its earlier purpose once again.

Neptune Energy Germany

4

3

21




2018

2018

2018

7.3

5.7

13.0

2017

2017

2017

7.0

5.7

12.7

Neptune Energy


Headcount


55Licences

~110


26


NORTH AFRICAALGERIA AND EGYPT

Production from North Africa, averaged 4.3 kboepd in 2018 and was slightly ahead of plan, reflecting the performance of our Egyptian assets. We expect significant growth in 2019 with first gas production in Algeria from the Touat development anticipated by mid-year. Production from Egypt is forecast to remain broadly unchanged.

Reserves and resourcesNeptune has 85 mmboe of proved plus probable (2P) net reserves in North Africa at the end of 2018, with the majority of these attributed to the Touat field in Algeria. In Egypt, the Group achieved close to 100 per cent proved plus probable reserves replacement following the positive Karam-9 well results.

DevelopmentIn 2018, Neptune continued to progress the Touat development with $78 million of capex expenditure attributable to our 35 percent indirect stake during the period. A similar level of capex is expected in 2019, including some re-phasing of projects from the prior period. We achieved a significant milestone in early 2019, with first gas accepted into the Touat facility as part of the commissioning process. Volumes are set to ramp-up throughout the year, with gas exports due to commence by the end of the first half of this year. At plateau, the Touat field will produce 75 kboepd gross. We continue to work proactively with our partners to improve HSSE performance, following the progress made in 2018.

Production from North Africa, averaged 4.3 kboepd in 2018 and was slightly ahead of plan, reflecting the performance of our Egyptian assets.

321

Assets

1. Touat, Algeria D2. Alam El Shawish West,

Egypt PO3. Ashrafi, Egypt PO

PO Partner operatedD Development

27

Strategic reportG


ents

In Egypt, five development wells were drilled and 22 workovers completed, with a similar level of activity anticipated in 2019. Neptune has achieved strong results from the workover programme.

ExplorationIn 2018, Neptune completed the drilling of the Bahga C-88 well in Egypt and testing is ongoing. The joint venture is currently evaluating drilling the Bagha South well in Egypt.

Neptune is actively looking to expand its presence in Egypt and since year end, we have been awarded a 100 per cent interest in the North West El Amal Offshore Concession in the central part of Gulf Suez. In the first phase, the work programme will include the acquisition of 100 km2 of 3D seismic and the drilling of one exploration well.

The Touat Production Sharing Contract covers 1,300 km2 close to the city of Adrar, in the Sahara deserts of Algeria.

Neptune Energy North Africa




2018

2018

2018

3.1

1.2

4.3

2017

2017

2017

3.4

1.5

4.9

Neptune Energy


Headcount

49Development capex on Touat

$78m2P reserves mmboe

85

1) Includes Egypt only for 2018 and 2017


28


2

1

ASIA PACIFICINDONESIA AND AUSTRALIA

In our Asia Pacific region, we achieved annual production of 21.3 kboepd in 2018. On a pro forma basis, this was up 13.4 kboepd on the prior year, reflecting the first full year of production from the non-operated Jangkrik field. Gross production from Jangkrik was maintained at a high level throughout the period, with a planned shutdown postponed.

During the period, unplanned downtime was limited and an umbilical replacement campaign carried out in December was completed four days earlier than planned.

Net production is expected to remain at a similar level in 2019, with a programme of two infill wells and a workover to mitigate declines. The PT Saka Energi carry reimbursement is expected to be completed in 2019 and this will increase our entitlement production from Q4.

The Asia Pacific region delivered strong earnings for the period, benefiting from higher production, lower operating costs and strong LNG realisations. Operating costs for the period were $12/boe, reflecting lower maintenance and logistic expenses.

Reserves and resourcesNeptune has 53 mmboe of proved plus probable (2P) net reserves in the Asia Pacific region at the end of 2018.

DevelopmentIn 2018, the focus of activity was on reservoir modelling of the Jangkrik reservoirs. The initial results from

In our Asia Pacific region, we achieved annual production of 21.3 kboepd in 2018.

Assets

1. Jangkrik, Indonesia PO2. Petrel, Australia D

PO Partner operatedD Development

29

Strategic reportG


ents

this and production history matching suggests that the reservoir may be more compartmentalised than previously thought. Planned infill drilling and workovers were deferred from 2018 and future investment will benefit from this improved understanding.

Work on the second tie-in project at the Bontang plant continues and will be completed in 2019. Physical pipeline gas sales will commence on completion of this project. Negotiations with domestic buyers are progressing well. The booster compression project remains on schedule for delivery in 2021.

In Australia, Neptune continues to progress subsurface work and evaluate development concepts for the Petrel gas field. Alternative export routes are being examined and additional seismic is planned.

ExplorationConsiderable exploration potential exists in acreage held by Neptune in the Kutei Basin in Indonesia and a high impact exploration well is planned with ENI in 2019.

We are partners in the Jangkrik licence in Indonesia. The first LNG cargo shipment was in June 2017, six weeks after the start of production and with an excellent HSE track record.

Neptune Energy Asia Pacific

Gas production for saleas LNG (kboepd)



2018

2018

2018

20.5

0.8

21.3

2017

2017

2017

7.4

0.4

7.8

Neptune Energy


Headcount

142P reserves mmboe

53Licences

~7


1) Includes Indonesia only for 2018 and 2017

30


FINANCIAL REVIEWSTRONG RESULTS

Business combinationsWe completed the acquisition of 100 per cent of the share capital of ENGIE E&P International S.A. (EPI) on 15 February 2018. EPI was the holding company for the worldwide exploration and production business of ENGIE, a large and diversified French energy, water and utility group. We acquired 70 per cent of the shares of EPI from ENGIE, for cash, as well as the 30 per cent owned by China Investment Corporation (CIC). CIC consequently became a shareholder in the Company’s parent, Neptune Energy Group Limited. At the same date, we arranged the repayment of certain loans provided to EPI by the ENGIE group.

This Annual Report therefore includes the results of the acquired EPI business consolidated since 15 February 2018, which is the acquisition date and when Neptune acquired control. As the effective date, or ‘locked-box’ date, of the EPI acquisition was 1 January 2016, Neptune has received the economic benefits of cash flows relating to the EPI business since that date, with cash flow for the interim period to closing of the acquisition effectively forming an adjustment to the acquisition price for accounting purposes. Comparative data for Neptune for the corresponding reporting period ended 31 December 2018, starting when the Company was incorporated on 22 March 2017, is not informative as Neptune had minimal activity for the period to 31 December 2017, principally comprising administration expenses in preparation for the EPI acquisition. Therefore, in respect of certain measures, including production, EBITDAX and capital expenditure, we have provided additional approximate pro forma information relating to the acquired EPI business, to enable a comparison of the results for the 12 months ended 31 December

2018 (including the period prior to the EPI acquisition on 15 February) with those for the 12 months ended 31 December 2017.

The acquisition of 100 per cent of the share capital of VNG Norge, for cash consideration, was completed on 28 September 2018 and the results of VNG Norge are consolidated from the start of the fourth quarter 2018.

The business combination accounting of EPI resulted in the recognition of $627.0 million of goodwill (revalued to $570.6 million as at 31 December 2018) and the acquisition of VNG Norge on 28 September 2018 resulted in the recognition of goodwill of $80.7 million (revalued to $76.2 million as at 31 December 2018). In each case, the goodwill arises largely as a result of the requirement to recognise deferred tax liabilities in respect of temporary differences between the fair value of oil and gas assets recorded in PP&E and their tax base available as future tax deductions.

In accordance with IFRS standards for accounting for business combinations, we have recorded the acquired assets and liabilities of both business combinations at the acquisition date at their fair values, or otherwise as required by IFRS. Oil and gas assets acquired were recorded at the net present value of expected future cash flows, post-tax, based on independent reserves reports, management plans and expectations and using projections of oil and gas prices based on a combination of forward prices and long-term Company assumptions. Liabilities were established in respect of decommissioning costs, post-employment benefits and deferred taxes. The assigned fair values are provisional in respect of VNG Norge and are subject to adjustment based on availability of additional information.

In 2018, Neptune Energy group delivered a strong operating profit of $1,049.3 million for the period to 31 December 2018, a year which saw a step change in the organisation.

2P reserves mmboe

638EBITDA $m

1,795EBITDAX $m

1,884Operating cash flow $m

1,156Average realised oil price $/bbl

69.6

More information

See page 87 for explanation of our approach to non-GAAP and non-IFRS measures.

31

Strategic reportG


ents

Results of operations

Neptune Energy$ millions

Period to31 December2018 (note a)

12 months ended

31 December 2017

Sales 2,537.9 –

EBITDAX (note b) 1,884.0 (3.7)

Operating profit (note c) 1,049.3 (3.7)

Profit before tax 906.1 (3.8)

Net profit (note e) 261.5 (3.8)

Net income before acquisition-related expenses (notes d and e) 324.4 (3.8)

a) Results for this period consolidate the acquired EPI business for the post acquisition period, from 15 February 2018 to 31 December 2018 and VNG Norge effective end of September 2018.

b) EBITDAX comprises net income for the period before income tax expense, financial expenses, financial income, non-recurring acquisition-related expenses, mark-to-market adjustments on commodity contracts, exploration expense and depreciation and amortisation.

c) Operating profit comprises current operating income after share in net income of entities accounted for using the equity method, and is stated before tax, finance costs, mark to-market on commodity contracts and non-recurring items.

d) Adjustment for acquisition-related expenses and taxes of $60.4 million incurred in connection with the EPI acquisition and a further $2.5 million in respect of VNG Norge.

e) The Group’s result for the year ended 31 December 2017 was a loss before and after tax of $3.8 million due to administrative expenses.

Total sales for the period ended 31 December 2018 were $2,537.9 million, reflecting total production of 50.9 mmboe and realised prices, before and after hedging, as shown in the table below. Our results benefited from strengthening markets for both oil and gas. The Brent crude price averaged $71.69 per barrel for the 12 months to 31 December 2018 and our average realised oil price was $70.0 per barrel for the period. The LNG sales prices are linked to a combination of movements in oil and gas market prices, depending on the contract.

Realised prices data Neptune Energy Pro forma information

15 February to31 December 2018 (note b)

Full year ended 31 December

2018

Full year ended 31 December

2017

Excluding impact of hedging:Average realised gas price ($/mcf) 7.9 8.1 6.4

Average realised LNG price ($/mcf) 8.2 7.5 6.1

Average realised oil price ($/bbl) 69.6 70.0 56.0

Average realised price, other liquids ($/bbl) (note a) 58.3 49.9 38.0

Including impact of hedging:Average realised gas price ($/mcf) 6.9 7.1 6.3

Average realised LNG price ($/mcf) 8.2 7.5 6.1

Average realised oil price ($/bbl) 67.5 67.5 51.6

Average realised price, other liquids ($/bbl) (note a) 58.3 49.9 38.0

a) Other liquids includes condensate and other natural gas liquidsb) Includes VNG Norway volumes from 1 October 2018

Operating costs were $520.6 million for the period to 31 December 2018 and our average operating cost per boe produced was $10.2/boe. This compares with average operating cost per boe of $10.5/boe for EPI for the year 2017. The lower per boe cost partly reflects reduced expense for LPG purchases at Jangkrik used for blending to meet LNG export specifications. Operating costs for the purpose of per boe expense are adjusted by $24.7 million for the period ended 31 December 2018 to exclude changes in the value of under-lifted entitlement to production and to net-off income

from tariffs and services which serve to recover costs.

Depreciation and amortisation expense of $656.1 million reflects an uplift in asset carrying values as a result of fair valuation of assets required for purchase accounting for the EPI and VNG business combinations. The charge represents $12.9/boe produced.

Exploration expense of $89.2 million reflects a high level of expense for seismic data acquisition as the Group seeks to add new licences and additional data to support upcoming exploration

programmes and as part of commercial arrangements to ensure ongoing access to data historically acquired by EPI, following its change of control.

General and administration expense of $131.6 million includes approximately $7 million non-recurring expenses related to recruitment and establishing Neptune as a new E&P company. Share in net income of entities accounted for under the equity method principally represents tariff income of one of our Dutch pipeline interests.

32


The Group’s operating profit for the period to 31 December 2018, reflecting the EPI contribution consolidated for 101 ⁄2 months from 15 February 2018 and VNG SA from 28 September 2018, was $1,049.3 million. Group EBITDAX for the period ended 31 December 2018 was $1,884.0 million, and for the full 12 months to 31 December 2018 pro forma EBITDAX including the EPI business from 1 January 2018 to the acquisition date was $2,056.0 million, compared with $1,485.0 million for the same period of 2017. The increase in EPI EBITDAX principally reflects higher realised prices, higher production in 2018 and lower costs.

The loss on mark-to-market of derivatives of $46.4 million relates to economic hedging transactions that do not qualify for hedge accounting treatment, and reflects the mark-to-market adjustment, net of previously recognised value changes recycled to sales in the period of the related physical production. Non-recurring acquisition-related expenses were $62.9 million, reflecting the requirement to charge business combination transaction expenses and related costs (such as taxes levied in respect of share transfers and change of control) to net income.

Net financial expenses were $143.2 million for the year, and include interest costs and unwinding of discounting of provisions.

The tax charge for the year represents 71 per cent of pre-tax income, including acquisition expenses of $62.9 million on which no tax relief is presently assumed. Adjusting for acquisition expenses, the effective tax rate was 67 per cent of pre-tax income.

Net income for the period was $261.5 million on a reported basis, or $324.4 million excluding non-recurring acquisition-related expenses of the EPI and VNG Norge acquisitions.

HedgingIn line with prudent risk management practice, we deploy non-margined derivative instruments to protect a certain percentage of its post-tax revenue against commodity price fluctuations on a rolling, three-year forward basis. While the Group actively manages its hedging programme through a mix of swaps and options, cost collars have emerged as the preferred structure since deal-close,

providing the core objective of downside protection while simultaneously enabling upside participation in rising price environments. The depth and market sophistication of our lending syndicate have left the Group well positioned with regards to commodity hedging, ensuring ample headroom and best-in-class pricing across the crude oil and natural gas complexes. We have a strong preference for hedging against the most liquid and mature benchmarks available, and the vast majority of our derivatives portfolio subsequently prices against Brent, TTF and NBP.

At acquisition of EPI, we inherited a substantial hedge book, which was novated from the ENGIE group to Neptune’s bank group. As at the acquisition date, the net fair value (mark-to-market) of this hedge book was a net liability of $53.6 million, which is reflected in the acquisition balance sheet. The liability reflected generally rising commodity prices since the hedges were put in place in prior years.

Since closing the EPI acquisition, Neptune has favoured a mechanistic, options-based programme. As at 31 December 2018, the approximate share of tax-effected production hedged for future periods was as shown in the table below.

At 31 December 2018, Neptune’s average weighted downside protection for 2019 was $57.0/barrel for oil and 5.6 mmbtu for gas. Downside protection for 2020 averaged $59.5/barrel for oil and 5.9 mmbtu for gas.

Aggregate post-tax hedge ratio: 2019 2020 2021

Oil 47% 21% 0%

Gas 56% 40% 13%

1) Oil price hedges include hedges of realisations for gas production sold as LNG and priced in relation to oil prices.

2) Post tax hedge ratios adjust for different tax rates on physical sales and hedge gains and losses, which mean that effective post tax hedges can be achieved through hedging contracts for volumes, which may be significantly less than anticipated sales.

The estimated net fair value (comprised of current and non-current assets and liabilities) on a mark-to-market basis of all our commodity derivative instruments at 31 December 2018, was a liability of $17.1 million, before tax, of which $27.8 million relate to contracts expiring in 2019.

Cash flowOperating cash flow, after cash taxes, for the period to 31 December 2018 was $1,156.4 million. Adjusted to exclude expenses relating to business combinations, this would have been $1,219.3 million.

Cash taxes paid were $535.1 million and largely relate to Norwegian taxes. The effective rate of cash tax as a percentage of pre-tax operating cash flow was 32 per cent.

Capital expenditureCash capital expenditure for the period to 31 December 2018, before acquisitions, was $461.3 million, including $20.3 million of capitalised exploration expenditure. This excludes expenditure at the Touat project, where the joint venture is accounted for under the equity method of accounting as a joint venture. Our statement of cash flows reflects investment at Touat in terms of the cash injections made to fund the joint venture company, which were $14.6 million in the year.

Group $ millions

Period to 31 December 2018 (note a)

Investing cash flows:Development capital expenditure 441.0

Acquisitions - assets 70.0

Exploration capital expenditure 20.3

Acquisitions- business combinations 3,546.5

Total cash capital expenditure 4,077.8

a) Results for this period relate to the post acquisition period only, from 15 February 2018 to 31 December 2018.

Total exploration expenditure comprised the $20.3 million cash capex plus $89.2 million expensed in respect of exploration and evaluation expenditure and unsuccessful write-offs.

Development cash capex was $441.0 million and in addition we incurred $70 million on the acquisition of the Seagull development and Isabella prospect from Apache. We have experienced some slippage and deferral of capex in 2018 compared with our plans and the original budgets prepared by EPI. We have also seen rephasing of some activities within the Njord project and reduced spend in Germany.

33

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On a pro forma basis, including capital expenditure prior to the EPI acquisition date, and including $78 million expenditure in respect of our 35 per cent indirect share of the Touat project, development capital expenditure by EPI for the 12 months ended 31 December 2018 was $643.7 million, compared with $779 million for the same period of 2017 on a comparable basis. The reduction in capital expenditure compared with the same period in 2017 principally reflects the completion of the Jangkrik project in mid-2017 and full completion of the Cygnus project including the Bravo production platform in August 2017.

We incurred $29.2 million on decommissioning expenditure in the period to 31 December 2018, principally at the L10 hub offshore in the Netherlands.

AcquisitionsInvestment in acquisitions includes the EPI and VNG Norge acquisitions in the year. Please refer to note 5 of the financial statements for further information.

On 1 August 2018, Neptune entered into an SPA to acquire certain development and exploration assets in the UK Central North Sea from a subsidiary of Apache Corporation (Apache). On 6 December 2018, the deal was completed and Neptune acquired Apache’s 35 per cent working interest in the Seagull development and a 50 per cent working interest in the Isabella exploration prospect.

Liquidity and capital resourcesManagement’s financial strategy is to manage Neptune’s capital structure with the aim that, across the business cycle, net debt to EBITDA remains modest. Given the strong operational performance and supportive commodity prices during 2018, we ended the year with a ratio of 0.89 times.

We funded our business with cash generated from operations and via the issuance of debt. At year end, we had the following debt outstanding:

• $1 billion drawn under a $2 billion, committed Reserve Base Lending (RBL) facility, which matures in 2024;

• $550 million of senior notes, paying a 6.625% coupon, maturing in 2025;

• $100 million Vendor Loan Note from ENGIE, maturing 2024; and

• $200 million project finance facility for Touat, which is payable from net revenues of the project.

At 31 December 2018, our cash balance totalled $197 million and our available and undrawn headroom under the RBL was $964 million. We also had $48 million of letters of credit outstanding, of which $34 million were drawn down from an ancillary facility under the RBL.

During 2018, Neptune was attributed an inaugural credit rating of Ba3 by Moody’s and BB- by Standard & Poor’s, which we will seek to strengthen over time.

All debt, with the exception of the RBL, is carrying a fixed interest rate. However, we swapped a sizeable amount of the RBL into fixed rate debt, taking advantage of historically low interest rates available in the market earlier in the year. As a result, 66 per cent of the debt portfolio at 31 December 2018 was fixed rate, which reduces Neptune’s exposure to increases in the USD Libor interest rate.

Strong operating performance in 2018 enabled us to pay a $380 million dividend to our shareholders and going forward we intend to pay a dividend that ensures a fair return to our investors in light of the Company’s performance and risk profile.

Going concernGiven the liquidity and capital resources arrangements in place, the consolidated accounts have been prepared on a going concern basis. The going concern basis is supported by future cash flow forecasts that support the Group on an ongoing basis.

Operating cost $/boe

10.2Development capex $m

461Net debt/EBITDA %

89Dividend $m

380

This Strategic report has been approved and signed on behalf of the Board.

Armand Lumens Chief Financial Officer 2 April 2019

34


CORPORATE GOVERNANCE AND DIRECTORS’ REPORTCOMMITTED TO THE HIGHEST STANDARDS OF ETHICS AND INTEGRITY

Strong governance and a culture of responsibility ensure we are well positioned to protect our people, the environment and our reputation.

Safety culture programmeA report from Norway

The safety essentials workshops in Norway were positively received with great engagement around what is needed in order to achieve safe performance and the importance of growing a strong safety culture.

Approximately 350 employees and contractors from every department, location and profession, took part in 25 workshops.

Local management introduced all sessions and underlined the importance of growing a strong safety culture where everyone participates and plays an important role. They also stressed that the workshops were an opportunity for the organisation to come up with ideas and give feedback. The participants took this challenge, and a lot of great

ideas on what is important in order to grow a strong safety culture came up in the workshops e.g. the importance of good teamwork, trust, openness both horizontally and vertically, cross-departmental collaboration and clear roles and responsibilities.

The workshops made it clear that there is high awareness across the organisation on the role everyone plays in safe operations. For example, participants from finance reflected upon the possible effects on safety of cutting costs in the ‘wrong areas’, participants from ICT discussed the consequences for safety of systems not working. All workshops had a mix of participants from different departments and professions, and due to this,

colleagues learned new perspectives that broadened the holistic understanding.

There is excitement and optimism about Neptune’s growth strategy in Norway. The feedback from the workshops is that culture is the key to performing and delivering and there is a high degree of willingness to create a great Neptune culture with a strong identity.

Executive leadership teamNeptune Energy is managed by the executive leadership team (ELT). This consists of senior management (see biographies on page 6), together with the heads of other functions and the managing directors of the countries in which we operate.

The ELT meets weekly to discuss operational matters such as health,

safety and environment (HSE), production, exploration and projects. The team is supported by our Investment Committee. The Committee meets, on average, once a fortnight to discuss items such as investments, drilling and exploration activities. Each month, the performance of the business is compared to the budget by means of a reforecasting and appraisal process.

Board meetingsAs part of the governance structure and processes, our three key investors and Executive Chairman are represented on the Board of NEGL, which is our ultimate parent undertaking and meets at least four times a year. Strategic matters and financial reporting are discussed during Board meetings and investor calls between the shareholders and representatives of senior management. The proceedings and decision-making are governed by a shareholders agreement.

Three committees form the backbone of our corporate governance structure: Audit & Risk Committee (ARC), Corporate Responsibility Committee (CRC) and Remuneration & Nomination Committee (RNC). The senior management members of these various Committees and the Investment Committee are indicated as part of the biographies on page 6. These are not yet formal Board sub committees but they prepare specific discussion and decision topics for Board meetings.

Our financial results are presented to bondholders and other interested parties every quarter through results announcements and a bondholder call. The publication of quarterly figures and this Annual Report are part of our commitment to provide transparent information to all of our stakeholders on a regular basis.

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Culture and values Our culture is centred on HSE, entrepreneurship, efficiency and value, attracting top E&P industry talent and creating an environment where our employees can flourish. Our values, as set out on page 8, are a core component of our business and help to guide our actions and those of the Company. These values are not unique, nor are they the only drivers for our success, but they are the platform upon which we build.

HSE is hugely important to us, and our HSE Policy applies to everybody working for and on behalf of the Company. Our goal is to conduct our business activities with no harm to people, no damage to the environment and no accident, today and in the future. We are committed to achieving best-in-class standards, ensuring continued safe and reliable operations across the whole organisation. The environment is a key consideration and we are committed to environmentally responsible operations, energy efficiency and the transition towards a low carbon future. Our Safety Culture programme is a fundamental part of our HSE Policy and is designed to ensure safe working is embedded in our thinking and in every action we take.

Our Code of Ethics and Business Integrity represents the cornerstone of a framework of ethics related policies. It sets out five principles of action (see page 8) designed to equip everyone working for the Company with the tools to make the right decisions and act in accordance with the highest ethical values.

Our Whistleblowing Policy and Whistleblowing Reporting Procedure seek to ensure that everyone working for the Company can raise any matters of genuine concern without fear of reprisals, safe in the knowledge that they will be taken seriously and that matters will be investigated appropriately and treated as confidential wherever possible. A report of a concern can be made through various internal reporting channels or using an external reporting line, Safecall.

Additional information on these policies, as well as our statement on modern slavery, is available on our website.

Directors’ and officers’ liabilityDirectors’ and officers’ liability insurance has been purchased by the Company and was in place throughout the period under review. The insurance does not provide cover in the event that the Director is proved to have acted fraudulently.

Directors’ statement of disclosure of information to the auditorEach of the Directors who held office at the date of approval of this Report confirm that, so far as they are aware, there is no relevant audit information of which the Company’s auditors are unaware, and that they have taken all steps they ought to have taken as Directors to make themselves aware of any relevant audit information and to establish that the Company’s auditors are aware of that information.

Employee engagementWe have established employee forums in every location where we operate at scale. We are committed to working with these groups to foster an environment of proactive engagement and two-way dialogue. We seek to raise awareness of company performance with these groups, and with our wider employee base, through regularly publishing and sharing our corporate and country performance scorecards.

Going concern The Directors consider that the Group and the Company have adequate resources to remain in operation for the foreseeable future and have therefore continued to adopt the going concern basis in preparing the financial statements.

Additional disclosuresOther information that is relevant to the Directors’ report and incorporated by reference into this report can be located as follows:

• Financial instruments and financial risk management: page 32 and note 2 on page 56.

• Events after the reporting period: note 29 on page 85.

• Future developments: pages 1 to 33.

The Company has chosen to include certain matters in its Strategic report that would otherwise be required to be disclosed in a Directors’ report. The Strategic report is on pages 1 to 33.

By order of the Board.

Sam Laidlaw Executive Chairman 2 April 2019

Company number: 10684661

Statement of Directors’ responsibilitiesThe Directors are responsible for preparing the Strategic Report, Directors’ Report and the financial statements in accordance with applicable UK law and regulations. Company law requires the Directors to prepare financial statements for each financial year. Under that law the Directors have elected to prepare the financial statements in accordance with International Financial Reporting Standards (IFRS) as published by the International Accounting Standards Board (IASB) and endorsed by the European Union but makes amendments where necessary in order to comply with Companies Act 2006. Under company law the Directors must not approve the financial statements unless they are satisfied that they give a true and fair view of the state of affairs of the Company and of the profit or loss of the Company for that period. In preparing these financial statements, the Directors are required to:

• select suitable accounting policies and apply them consistently;

• make judgements and accounting estimates that are reasonable and prudent;

• state whether IFRS has been followed, subject to any material departures disclosed and explained in the financial statements; and

• prepare the financial statements on the going concern basis unless it is inappropriate to presume that the Company will continue in business.

The Directors are responsible for keeping adequate accounting records that are sufficient to show and explain the Company’s transactions and disclose with reasonable accuracy at any time the financial position of the Company and enable them to ensure that the financial statements comply with the Companies Act 2006. They are also responsible for safeguarding the assets of the Company and hence for taking reasonable steps for the prevention and detection of fraud and other irregularities.

36


INDEPENDENT AUDITOR’S REPORT TO THE MEMBERS OF NEPTUNE ENERGY GROUP MIDCO LIMITEDOpinionWe have audited the financial statements of Neptune Energy Group Midco Limited (‘the parent company’) and its subsidiaries (the ‘group’) for the year ended 31st December 2018 which comprise the Consolidated Income Statement, Consolidated Statement of Comprehensive Income, Consolidated and Company Statement of Financial Position, Consolidated and Company Statement of Changes in Equity, Consolidated and Company Statement of Cashflows and the related notes 1 to 29, including a summary of significant accounting policies. The financial reporting framework that has been applied in their preparation 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 group’s and of the parent company’s affairs as at 31st December 2018 and of the group’s profit 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 IFRSs as adopted by the European Union 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 below. We are independent of the group and 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, 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.

Conclusions relating to going concernWe have nothing to report in respect of the following matters in relation to which the ISAs (UK) require us to report to you where:

• the directors’ use of the going concern basis of accounting in the preparation of the financial statements is not appropriate; or

• the directors have not disclosed in the financial statements any identified material uncertainties that may cast significant doubt about the group’s or the parent company’s ability to continue to adopt the going concern basis of accounting for a period of at least twelve months from the date when the financial statements are authorised for issue.

Other information The other information comprises the information included in the annual report, other than the financial statements and our auditor’s report thereon. The directors are responsible for the other information.

Our opinion on the financial statements does not cover the other information and, except to the extent otherwise explicitly stated in this report, we do not express any form of assurance conclusion thereon.

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 the 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 2006In 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 directors’ report have been prepared in accordance with applicable legal requirements.

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Matters on which we are required to report by exceptionIn 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 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 directorsAs explained more fully in the directors’ responsibilities statement set out on page 35, 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, but 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 at https://www.frc.org.uk/auditorsresponsibilities. This description forms part of our auditor’s report.

Use of our reportThis report is made solely to the 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 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 company and the company’s members as a body, for our audit work, for this report, or for the opinions we have formed.

Steven Dobson Senior statutory auditor for and on behalf of Ernst & Young LLP, Statutory Auditor London 02 April 2019

Notes

1. The maintenance and integrity of the Neptune Energy Group Midco Limited web site is the responsibility of the directors; the work carried out by the auditors does not involve consideration of these matters and, accordingly, the auditors accept no responsibility for any changes that may have occurred to the financial statements since they were initially presented on the web site.

2. Legislation in the United Kingdom governing the preparation and dissemination of financial statements may differ from legislation in other jurisdictions.

38


Consolidated income statement

Group In millions of $ Notes

Year ended31 December

2018

Period from22 March to

31 December2017

Revenue 3 2,537.9 –

Cost of sales 6 (1,203.3) –

GROSS PROFIT 1,334.6 –

Exploration expenses 6 (89.2) –

General and administration expenses (131.6) (3.7)

Share of net income from investments using equity method 4.0 –

OPERATING PROFIT/(LOSS) AFTER EQUITY ACCOUNTED INVESTMENTS 4 1,117.8 (3.7)

Other operating gains/(losses) 8 (68.5) –

OPERATING PROFIT/(LOSS) BEFORE FINANCIAL ITEMS 1,049.3 (3.7)

Finance costs 9 (149.7) (0.1)

Finance income 9 6.5 –

PROFIT/(LOSS) BEFORE TAX 906.1 (3.8)

Taxation 11 (644.6) –

NET PROFIT/(LOSS) 261.5 (3.8)

All profits and losses arise as a result of continuing operations. The accounting policies on page 44 to 55 together with the notes on pages 56 to 85 form part of these accounts.

Consolidated statement of comprehensive income



2018


31 December2017

Profit/(loss) for the period 261.5 (3.8)

Items that may be reclassified to the income statement:

Hedge adjustments net of tax1 20 (25.1) –

Foreign currency translation (142.8) –

(167.9) –

Other items not reclassified to the income statement:

Remeasurement of defined pension obligations, net of tax2 (0.1) –

OTHER COMPREHENSIVE INCOME (168.0) –

TOTAL COMPREHENSIVE INCOME/(LOSS) FOR THE PERIOD, NET OF TAX 93.5 (3.8)

1) Income tax related to hedge adjustments is $3.3 million (2017: $nil)

2) Income tax related to defined benefit obligations is $3 million (2017: $nil)

CONSOLIDATED FINANCIAL STATEMENTSFOR THE YEAR ENDED 31 DECEMBER 2018

39

Governance

Financial statements

Strategic report

Consolidated statement of financial position – Group


31 December2018

31 December2017

NON-CURRENT ASSETS

Goodwill 12 646.8 –

Intangible assets 13 112.5 –

Property, plant and equipment 14 3,922.2 –

Derivative instruments 20 40.1 –

Investments in entities accounted for using the equity method 15 540.9 –

Other non-current assets 20 8.8 –

Equity instruments 20 19.7 –

Deferred tax assets 11 438.6 –

TOTAL NON-CURRENT ASSETS 5,729.6 –

CURRENT ASSETS


Trade and other receivables 17 642.6 0.4

Inventories 16 64.3 –

Cash and cash equivalents 18 197.3 0.4

Tax receivable 83.7

TOTAL CURRENT ASSETS 1,021.1 0.8

TOTAL ASSETS 6,750.7 0.8

Share capital 24 1,977.2 –

Hedging reserve 20 (25.1) –

Foreign currency translation (142.8) –

Retained earnings/(deficit) (122.4) (3.8)

TOTAL EQUITY 1,686.9 (3.8)

NON-CURRENT LIABILITIES

Provisions 23 1,675.2 –

Long-term borrowings 19 1,788.2 –


Income tax payable 35.7 –

Other non-current liabilities 22 59.6 –

Deferred tax liabilities 11 582.2 –

TOTAL NON-CURRENT LIABILITIES 4,172.0 –

CURRENT LIABILITIES

Provisions 23 69.3 –

Short-term borrowings 19 – 3.1


Trade and other payables 22 94.5 1.5

Income tax payable 188.1 –

Other current liabilities 22 466.3 –

TOTAL CURRENT LIABILITIES 891.8 4.6

TOTAL EQUITY AND LIABILITIES 6,750.7 0.8

The accounts on pages 38 to 85 were approved by the Board and signed on its behalf by :

Armand Lumens, Chief Financial Officer

40


Statement of financial position – Company

CompanyIn millions of $ Notes

31 December2018

31 December2017

NON-CURRENT ASSETS

Investments 15 1,977.2 –

Inter-company loan receivable 17 654.0 –

TOTAL NON-CURRENT ASSETS 2,631.2 –

CURRENT ASSETS

Inter-company loan receivable 17 – 3.1

Cash and cash equivalents 18 1.1 –

Other current assets 17 0.2 –

TOTAL CURRENT ASSETS 1.3 3.1

TOTAL ASSETS 2,632.5 3.1

Share capital 24 1,977.2 –

Retained earnings b/fwd – –

Retained earnings 0.6 –

TOTAL EQUITY 1,977.8 –


Inter-company loan payable 22 654.7 –

TOTAL NON-CURRENT LIABILITIES 654.7 –

CURRENT LIABILITIES

Inter-company loan payable – 3.1

TOTAL CURRENT LIABILITIES – 3.1

TOTAL EQUITY AND LIABILITIES 2,632.5 3.1

As permitted by Section 408 of the Companies Act 2006, no income statement or statement of comprehensive income is presented for the Company. Profit for the year was $380.6 million.

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Consolidated statement of changes in equity – Group

GroupIn millions of $

Share capital

Hedgingreserve2

Foreigncurrency

translation3 Retainedearnings Total

AS AT 22 MARCH 2017 (INCORPORATION) – – – – –

Profit/(loss) for the period – – – (3.8) (3.8)

Other comprehensive income – – – – –

TOTAL COMPREHENSIVE INCOME – – – (3.8) (3.8)

TRANSACTIONS WITH OWNERS OF THE COMPANY:

Issue of ordinary shares1 – – – – –

AS AT 1 JANUARY 2018 – – – (3.8) (3.8)

Profit for the period – – – 261.5 261.5

Other comprehensive income – (25.1) (142.8) (0.1) (168.0)

TOTAL COMPREHENSIVE INCOME – (25.1) (142.8) 261.4 93.5


Issue of ordinary shares related to business combinations (note 24) 1,977.2 – – – 1,977.2

Dividends paid (note 10) – – – (380.0) (380.0)

BALANCE AS AT 31 DECEMBER 2018 1,977.2 (25.1) (142.8) (122.4) 1,686.9

1) On Company incorporation 728 $1 shares were allotted, called up and fully paid

2) The hedging reserve represents gains and losses on derivatives classified as effective cash flow hedges

3) The foreign currency translation reserve represents exchange gains and losses arising on translation of foreign currency subsidiaries

Statement of changes in equity – Company

Company In millions of $

Share capital

Retainedearnings Total

AS AT 22 MARCH 2017 (INCORPORATION) – – –

Loss for the period – – –

Other comprehensive income – – –

TOTAL COMPREHENSIVE INCOME – – –


Issue of share capital1 – – –

AS AT 1 JANUARY 2018 – – –

Profit for the period – 380.6 380.6

Other comprehensive income – – –

TOTAL COMPREHENSIVE INCOME – 380.6 380.6


Issue of share capital (note 24) 1,977.2 – 1,977.2

Dividends (note 10) – (380.0) (380.0)

BALANCE AS AT 31 DECEMBER 2018 1,977.2 0.6 1,977.8

1) On Company incorporation 728 $1 shares were allotted, called up and fully paid

The consolidated statement of equity for the Company and Group at 1 January 2018 was the same at $3.8 million.

42


Consolidated cash flow statement – Group



2018


31 December2017

CASH FLOWS FROM OPERATING ACTIVITIES

Profit/(loss) before taxation 906.1 (3.8)

Adjustments to reconcile profit/(loss) before tax to net cash flows:

Depletion, depreciation and amortisation 656.1 –

Unsuccessful exploration costs written off 7.6 –

Finance costs 149.7 –

Finance income (6.5) –

Share of net income from investments accounted using equity method (4.0) –

Fair value change in contingent consideration (21.0) –

Other non-cash income and expenses (0.4) –

Net loss on derivative instruments 46.4 –

Movement in provisions including decommissioning expenditure (53.6) –

Working capital adjustments 11.1 1.2

Income tax paid (net) (535.1) –

NET CASH FLOWS FROM/(USED IN) OPERATING ACTIVITIES 1,156.4 (2.6)

CASH FLOWS FROM INVESTING ACTIVITIES

Expenditure on exploration and evaluation assets (20.3) –

Expenditure on property, plant and equipment (511.0) (0.1)

Expenditure on business combination and acquisitions, net of cash acquired (3,546.5) –

Proceeds from sale of equity investments 4.3 –

Finance income received 6.1 –

Investment made in equity accounted investments (14.6) –

NET CASH USED IN INVESTING ACTIVITIES (4,082.0) (0.1)

CASH FLOWS FROM FINANCING ACTIVITIES

Proceeds from issue of shares 1,977.2 –

Proceeds from loans and borrowings 3,192.3 3.1

Repayment of loans and borrowings (1,510.3) –

Finance costs paid (149.6) –

Dividend paid (380.0) –

NET CASH FLOWS FROM FINANCING ACTIVITIES 3,129.6 3.1

Net increase in cash and cash equivalent 204.0 0.4

Cash and cash equivalents at 1 January 0.4 –

Net foreign exchange differences (7.1) –

CASH AND CASH EQUIVALENTS AS AT 31 DECEMBER 197.3 0.4

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Cash flow statement – Company

CompanyIn millions of $


2018


31 December2017

CASH FLOWS FROM OPERATING ACTIVITIES

Profit/(loss) before taxation 380.6 –

Adjustments to reconcile profit before tax to net cash flows:

Finance costs 31.8 –

Finance income (411.1) –

Working capital adjustments (0.2) –

NET CASH FLOWS FROM OPERATING ACTIVITIES 1.1 –

CASH FLOWS FROM INVESTING ACTIVITIES

Loans made to subsidiaries (650.9) (3.1)

Expenditure on investments (1,977.2) –

Finance income received 31.1

Dividend received 380.0 –

NET CASH FLOWS FROM INVESTING ACTIVITIES (2,217.0) (3.1)

CASH FLOWS FROM FINANCING ACTIVITIES

Proceeds from issue of shares 1,977.2 –

Proceeds from loans and borrowings 651.6 3.1

Dividend paid (380.0) –

Finance costs paid (31.8) –

NET CASH FLOWS FROM FINANCING ACTIVITIES 2,217.0 3.1

Net increase in cash held 1.1 –

Cash at 1 January 2018 – –

Net foreign exchange differences – –

CASH AS AT 31 DECEMBER 1.1 –

The notes on page 56 to 85 form part of these accounts.

44


General information Neptune Energy Group Midco Limited is a limited company, incorporated and domiciled in the United Kingdom. The registered office is located at Nova North, 11 Bressenden Place, London SW1E 5BY.

The consolidated financial statements of Neptune Energy Group Midco Limited and its subsidiaries (collectively, the Group) for the year ended 31 December 2018 were authorised for issue in accordance with a resolution of the Board on 2 April 2019.

The Group is principally engaged in oil and gas exploration and production.

1. Basis of preparation The consolidated financial statements for the year ended 31 December 2018 have been prepared in accordance with International Financial Reporting Standards (IFRS) as adopted by the European Union (EU).

The preparation of financial statements in conformity with IFRS requires the use of certain critical accounting estimates. It also requires management to exercise its judgement in the process of applying the Group’s accounting policies. The areas involving a higher degree of judgement or complexity, or areas where assumptions and estimates are significant to the consolidated financial statements, are disclosed below in note 1.3.

The accounting policies adopted in the preparation of these consolidated financial statements are consistent with those followed in the preparation of the Group’s annual consolidated financial statements for the period ending 31 December 2017 and are detailed below. During 2018, the Group has also implemented a number of additional accounting policies, also disclosed below, related to businesses acquired during the period (see note 5) as well as the adoption of new standards effective as of 1 January 2018. The Group has not early-adopted any other standard, interpretation or amendment that has been issued but is not yet effective.

1.1 NEW STANDARDS, INTERPRETATIONS AND AMENDMENTS ADOPTED BY THE GROUPThe Group has applied IFRS 15 Revenue from Contracts with Customers and IFRS 9 Financial Instruments; implementation of these standards does not have any significant impact on the Group’s results in 2018 and previously reported financial statements as the Group neither reported any revenue nor held any financial instruments during 2017.

IFRS 9 replaces IAS 39 Financial Instruments: Recognition and Measurement for annual periods beginning on or after 1 January 2018, bringing together all three aspects of the accounting for financial instruments: classification and measurement; impairment; and hedge accounting. The Group adopted the hedge accounting requirements of IFRS 9 effective 1 January 2018, and post the acquisition of EPI the Group’s hedging relationships treatment continued in alignment with the Group risk management strategy.

IFRS 15 is a new standard under which revenue is recognised when the customer obtains control of goods or services promised in the contract, for the amount of consideration to which an entity expects to be entitled in exchange for said promised goods or services. IFRS 15 has not impacted the presentation of the Group’s sales revenue in 2018. The Group’s accounting policy is that revenue is recognised when the Group satisfies a performance obligation by transferring oil and gas to a customer. The title to oil and gas typically transfers to a customer at the same time as the customer takes physical possession of the commodity, which is when the performance obligation is fully satisfied.

Several other financial reporting amendments and interpretations apply for the first time in 2018, but do not have an impact on the consolidated financial statements of the Group.

IFRS 16 Leases was issued in 2016 to replace IAS 17 Leases and is required to be adopted by 2019. Under the new standard all lease contracts, with limited exceptions, are recognised in financial statements by way of right-of-use assets and corresponding lease liabilities. The Group will apply the modified retrospective approach, which means that the cumulative effect of initially applying the standard is recognised at the date of initial application and there is no restatement of comparative information.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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The application of the standard will impact both the measurement and disclosures of leases over a low-value threshold, with terms longer than one year and on the classification of expenditures and consequently the classification of cash flow from operating activities, cash flow from investing activities and cash flow from financing activities. It will also impact the timing of expenses recognised in the statement of income. The adoption of the new standard at 1 January 2019, is expected to have a negligible impact on equity following the recognition of lease liabilities of approximately $69.3 million and additional right-of-use assets of approximately $69.3 million. These liabilities will be measured at the present value of the remaining lease payments, discounted using the Group’s marginal cost of finance as of 1 January 2019, which is the Company’s rate on its corporate reserve based lending facility currently 5.7 per cent. A 1 per cent change in the cost of borrowing would impact the value of lease liabilities on transition by $2.2 million.

The following categories of leases have been identified: land, buildings (offices, warehouses and supply bases), transportation assets (helicopter, supply and standby vessels), property, plant and equipment. Where the asset is dedicated to an operated joint venture the Company reports its net equity share of the lease rather than the gross amount. Where there are options to extend a contract and it is reasonably certain that the contract will be extended, the lease period extension is included in the assessment. The right-of-use asset is recognised within property, plant and equipment at the present value of the liability at the commencement date of the lease, adding any directly attributable costs. The right-of-use asset is depreciated on a straight line basis over the lease term.

The Group has elected to use the exemptions proposed by the standard on lease contracts for which the lease terms ends within 12 months as of the date of initial application, and lease contracts for which the underlying asset is of low value. These leases will continue to be accounted as operating leases and are not material in the context of the Group financial results. Furthermore, the use of a single discount rate is applied to a portfolio of leases with reasonably similar characteristics.

The impact of adopting IFRS 16 on 1 January 2019 will be the immediate recognition of right-of-use assets of approximately $69.3 million and lease liabilities of approximately $69.3 million, with an expected reclassification of costs in 2019 that would previously have been reported under operating lease expenses to depreciation of leased assets and unwinding of the discount on leased assets.

Current Non-current

Value ontransition

$m

Land 0.1 0.8 0.9

Buildings 6.7 23.8 30.5

Transportation 9.0 28.2 37.2

Property, plant and equipment 0.2 0.5 0.7

TOTAL 16.0 53.3 69.3

In light of the recent IFRIC pronouncement, the assessment of whether a lease liability incurred by an operator should be recorded net or gross, in accordance with IFRS 16 and IFRS 11, is currently under review. Had the above lease liability been presented on a gross basis, the right-of-use asset and lease liability would have been $160.4 million on transition.

The difference between the closing 2018 value of operating lease commitments and the opening value to be recognised as right-of-use assets arises primarily as a result of certain assets within the Group not falling into the scope of IFRS 16, while previously being in scope of IAS 17. The discount rate applied to calculate the right-of-use has also driven the difference.

1.2 MEASUREMENT AND PRESENTATION BASIS The consolidated financial statements have been prepared on a historical cost basis, except for derivative financial instruments, debt and equity financial assets and contingent consideration that have been measured at fair value. The carrying values of recognised assets and liabilities that are designated as hedged items in fair value hedges that would otherwise be carried at amortised costs are adjusted to recognise changes in the fair value attributable to the risks that are being hedged in effective hedge relationships.

The consolidated financial statements are presented in US dollars and rounded to millions, except where otherwise indicated.

1.3 SIGNIFICANT JUDGEMENTS AND ESTIMATESEstimates and judgements are continually evaluated and are based on historical experiences and other factors, including expectations of future events that are believed to be reasonable under the circumstances.

1.3.1 EstimatesThe preparation of consolidated financial statements requires the use of estimates and assumptions to determine the value of assets and liabilities and contingent assets and liabilities at the reporting date, as well as revenues and expenses reported during the period.

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Notes to the consolidated financial statementscontinued

The key estimates used in preparing the Group’s consolidated financial statements relate mainly to:

• measurement of the recoverable amount of property, plant and equipment, other intangible exploration assets and goodwill;

• calculations of depreciation and amortisation which involve estimates of volumes of commercial reserves of oil and gas;

• measurement of provisions, particularly for decommissioning obligations;

• measurement of recognised tax loss carry-forwards; and

• assessments of fair value of assets and liabilities acquired as part of a business combination.

Each of these categories of key estimates are described further below. Due to uncertainties inherent in the estimation process, the Group regularly revises its estimates in light of currently available information. Final outcomes could differ from those estimates.

Recoverable amount of intangible assets and property, plant and equipment and goodwillThe recoverable amounts of intangible assets and property, plant and equipment and goodwill are based on estimates and assumptions, regarding in particular the expected market outlook (including future commodity prices) used for the measurement of cash flows, estimates of the volume of commercially recoverable reserves and resources of oil and gas future production rates and costs to develop reserves and resources, and the determination of the discount rate.

Any changes in these assumptions may have a material impact on the measurement of the recoverable amount and could result in adjustments to any impairment losses to be recognised.

See note 12, 13 and 14 for further information.

Commercial reserves and depreciation of oil and gas production assets Charges for depreciation and amortisation of oil and gas producing properties are calculated on a unit of production rate based on production as a proportion of estimated quantities of proved and probable oil and gas reserves. The Group has adopted the definitions and guidelines presented in the Petroleum Resources Management System (SPE-PRMS 2007) for the classification and reporting of commercial reserves and resources of oil and gas. Commercial reserves are those in the proved and probable categories of reserves. See note 14 for further information on the depreciation and amortisation of the Group’s assets.

Estimates of reserves is a subjective process involving estimating underground resource accumulations and recovery rates, and is a function of many factors, such as the properties of the reservoir rock and petroleum fluid. Changes in the estimates of commercial reserves will consequently impact depreciation and amortisation expense. Changes in factors or assumptions used in estimating reserves could include:

• changes due to revised estimates of volumes in place and recovery factors;

• the effect on proved and probable reserves of differences between actual commodity prices and assumptions; and

• unforeseen operational issues.

Estimates of decommissioning provisionsParameters having a significant influence on the amount of provisions for decommissioning costs include the forecast of costs to be incurred to decommission facilities, plug wells and restore sites used for production and drilling, the anticipated scope of such decommissioning obligations, which may depend on laws and regulation in force at the time, the timing of such expenditure and the discount rate applied to forecast cash flows. These parameters are based on information and estimates deemed to be appropriate by the Group at the current time.

The modification of certain parameters could involve a significant adjustment of these provisions.

See note 23 for further information.

Measurement of recognised tax loss carry-forwardsDeferred tax assets are recognised on tax loss carry-forwards when it is probable that taxable profit will be available against which the tax loss carry-forwards can be utilised. The estimates of the taxable profit that will be available against which the unused tax losses can be utilised, are based on taxable temporary differences relating to the same taxation authority and the same taxable entity and estimates future taxable profits. These estimates and utilisations of tax loss carry-forwards are prepared on the basis of profit and loss forecasts as included in the medium-term business plan and, if necessary, on the basis of additional forecasts. See note 11 for further information.

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Business combinationIn accounting for the acquisition of EPI and VNG Norge AS, as disclosed in note 5, the identifiable assets and liabilities acquired were recognised at their fair value in accordance with IFRS 3 Business Combinations. The determination of their fair values is based, to a considerable extent, on estimates and judgements. The significant estimates used to determine these fair values are consistent with those discussed above and the significant judgement in determining commercial reserves is discussed below in note 1.3.2.

1.3.2 JudgementsAs well as relying on estimates, the Directors make judgements to define the appropriate accounting policies and decisions to apply to certain activities and transactions, including when the effective IFRS standards and interpretations do not specifically deal with the related accounting issues. Key areas of judgement include:

Carrying value of intangible exploration and evaluation assets: the amounts capitalised for exploration and evaluation assets represent cost in respect of active exploration and appraisal projects. These amounts will be written off to the income statement as exploration expense unless commercial reserves are established or the determination process as to the success or otherwise of the activity is not yet completed and there are no indications of impairment in accordance with the Group’s accounting policy. The process of determining whether there is an indicator of impairment or calculating the impairment requires critical judgement, including: the Group’s intention to proceed with a future work programme for a prospect or licence; the likelihood of licence renewal or extension; the assessment of whether sufficient data exists to indicate that, although a development in the specific area is likely to proceed, the carrying amount of the exploration and evaluation asset is unlikely to be recovered in full from successful development or by sale, and the success of a well result.

Commercial reserves: the estimation of commercial reserves of oil and gas in accordance with SPE-PRMS guidelines, as outlined above, involves complex technical judgements. These complex technical judgements include estimates of oil and gas in place, recovery factors and future commodity prices which have an impact on the total amount of recoverable reserves. Future development costs are estimated taking into consideration the level of development required based on internal functional specialists or operator assessments, where applicable.

1.4 BASIS OF CONSOLIDATION Subsidiaries and business combinationsSubsidiaries are all entities over which the Group has control. The Group consolidates an entity when it is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. Subsidiaries are fully consolidated from the date on which control is transferred to the Group (the acquisition date).

Inter-company transactions, balances and unrealised gains on transactions between Group companies are eliminated. Unrealised losses are also eliminated.

Where necessary, amounts reported by subsidiaries have been adjusted to conform with the Group’s accounting policies.

The Group applies the acquisition method to account for business combinations. The consideration transferred for the acquisition of a subsidiary is the fair value of the assets transferred, the liabilities incurred to the former owners of the acquiree, and the equity interests issued by the Group. The consideration transferred includes the fair value of any asset or liability resulting from a contingent consideration arrangement.

Identifiable assets acquired, and liabilities and contingent liabilities assumed in a business combination, are measured initially at their fair value at the acquisition date. The fair value of acquired oil and gas properties is based on the post-tax net present value of expected future cash flows. The fair values of assets and liabilities acquired which are initially recognised at provisional amounts may be adjusted within 12 months of the acquisition date based on the assessment of additional data relating to the conditions of items as at the acquisition date.

Acquisition-related costs of a business combination are expensed as incurred.

Any contingent consideration to be transferred by the Group is recognised at fair value at the acquisition date. Subsequent changes to the fair value of the contingent consideration are recognised in accordance with IFRS 9 in profit or loss.

Goodwill arising in a business combination is recognised as an asset at the acquisition date. Goodwill is measured as the excess of the sum of the consideration transferred over the net of the acquisition-date amounts of the identifiable assets acquired and the liabilities assumed. After initial recognition, goodwill is measured at cost less any accumulated impairment losses. For the purpose of impairment testing, goodwill acquired in a business combination is, from the acquisition date, allocated to each of the Group’s cash-generating units (CGUs) that are expected to benefit from the combination, irrespective of whether other assets or liabilities of the acquiree are assigned to those units.

Where goodwill has been allocated to a CGU and part of the operation within that unit is disposed of, the goodwill associated with the disposed operation is included in the carrying amount of the operation when determining the gain or loss on disposal. Goodwill disposed in these circumstances is measured based on the relative values of the disposed operation and the portion of the CGU retained. The carrying value of goodwill is reviewed at least annually at the end of the financial year or following a trigger event.

48



If the Group’s interest in the fair value of the acquiree’s identifiable net assets exceeds the sum of the consideration transferred, the excess is recognised immediately in net income.

For the Company, fixed asset investments, including investment in subsidiaries, are stated at cost and reviewed for impairment if there are any indications that the carrying value may not be recoverable.

Investments in joint operations and joint venturesA joint arrangement is one in which two or more parties have joint control and may take the form of a joint operation or a joint venture. Joint control is the contractually agreed sharing of control of an arrangement, which exists when decisions about the relevant activities require the unanimous consent of the parties sharing control.

Most of the Group’s activities are conducted through joint operations, whereby the parties that have joint control of the arrangement have rights to the underlying assets, and obligations for the liabilities, relating to the arrangement. The Group reports its share of the assets, liabilities, income and expenses of the joint operation within the equivalent items in the consolidated financial statements, on a line-by-line basis. Certain of the Group’s joint operations derive from production sharing contracts (PSCs), entered into with host governments or their agencies. PSCs typically result in economic rights similar to other licence and concession arrangements and are accounted for using the same line-by-line basis, with the Group using an appropriate unit of production basis to recognise its share of production and reserves attributable to the PSC.

A joint venture, which normally involves the establishment of a separate legal entity, is a contractual arrangement whereby the parties that have joint control of the arrangement have the rights to the arrangement’s net assets. The results, assets and liabilities of a joint venture are incorporated in the consolidated financial statements using the equity method.

Interests in associatesAn associate is an entity over which the Group has significant influence, through the power to participate in the financial and operating policy decisions of the investee, but which is not a subsidiary or a joint arrangement. Interests in associates are accounted for using the equity method.

1.5 FOREIGN CURRENCY TRANSLATIONPresentation and functional currency Items included in the consolidated financial statements are measured using the currency of the primary economic environment in which each Group company operates (its functional currency). The financial statements are presented in US dollars, which is the Company’s presentation and functional currency.

Transactions and balancesForeign currency transactions are translated into the functional currency using exchange rates prevailing at the dates of the transactions. Monetary assets and liabilities denominated in foreign currencies are remeasured at the end of each accounting period. Foreign exchange gains and losses resulting from the settlement or revaluation of monetary assets and liabilities denominated in foreign currencies are recognised in the income statement, except when deferred in other comprehensive income as qualifying cash flow hedges and qualifying net investment hedges (if applicable). Foreign exchange gains and losses included in net income are presented within ‘Foreign exchange gain/loss’ as part of financial income/expense.

Group companiesThe results and financial position of all of the Group entities (none of which has the currency of a hyper-inflationary economy) that have a functional currency different from the presentation currency are translated into the presentation currency as follows:

• assets and liabilities for each balance sheet presented are translated at the closing rate at the date of that balance sheet;

• income and expenses for each income statement are translated at average exchange rates (unless this average is not a reasonable approximation of the rates prevailing on the transaction dates, in which case income and expenses are translated at the rate on the dates of each transaction);

• the exchange differences arising on translation for consolidation are recognised in other comprehensive income; and

• any goodwill arising on the acquisition of a foreign operation and any fair value adjustments to the carrying amounts of assets and liabilities arising on the acquisition are treated as assets and liabilities of the foreign operation and are translated at the spot rate of exchange at the reporting date.

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1.6 INTANGIBLE ASSETS Intangible assets (other than goodwill and exploration and evaluation rights) are carried at cost less any accumulated amortisation and any accumulated impairment losses. These assets principally comprise IT software and are amortised on a straight line basis over their useful economic lives.

1.7 ASSETS RELATING TO THE EXPLORATION AND PRODUCTION OF MINERAL RESOURCESi) Acquisition costs of unproved properties: Exploration licences and concessions correspond to licences or rights acquired in

areas in which the existence of oil and gas reserves has not yet been demonstrated. The costs of acquiring such exploration licences are capitalised within intangible assets.

ii) Exploration and evaluation costs: The Group adopts the successful efforts method of accounting for exploration and evaluation costs. Costs incurred prior to the award of a licence are expensed in the period in which they are incurred. The costs of geological and geophysical surveys and studies are expensed in the period incurred. Exploration and appraisal drilling costs are capitalised in cost centres by well, field or exploration area, as appropriate, pending the results of the exploration activities. Internal costs are expensed unless directly attributed to drilling operations. Costs are then written off as exploration expense in the income statement unless commercial reserves have been established or if the determination process has not been completed and there are no indications of impairment. When the exploratory phase has resulted in the recognition of commercial reserves, the related costs are first assessed for impairment and (if required) any impairment recognised, then the remaining balance is transferred to property, plant and equipment.

iii) Property, plant and equipment: Expenditure on the acquisition of proved properties and on the construction, installation or completion of facilities such as platforms, pipelines and the drilling of development wells, including any development or delineation wells, is capitalised within oil and gas properties – PP&E.

In accordance with IAS 16, the initial cost of assets relating to the exploration and production includes an initial estimate of the costs of decommissioning, and restoring the site on which the facilities are located when production operations cease, when the entity has a present legal or constructive obligation for decommissioning or to restore the site. A corresponding provision for this decommissioning obligation is recorded for the amount of the asset component.

Borrowing costs that are directly attributable to the construction of the qualifying asset are capitalised as part of the cost of that asset.

iv) Depreciation of production assets: The depreciation of production assets, including decommissioning costs, starts when the oil or gas field is brought into production, and is based on the unit of production method. According to this method, the depletion rate is equal to the ratio of oil and gas production for the period to proved and probable reserves, as applied to the capitalised cost plus future estimated costs to develop those reserves.

Pipeline assets for which third-party tariff income is the main source of revenue are depreciated on a straight line basis over a period not exceeding the projected useful economic life of the asset.

v) Recognition and derecognition of assets: Acquired assets are valued at their purchase price and assessed for impairment (if required). An item of property, plant and equipment is derecognised upon disposal or when no future economic benefits are expected to arise from the continued use of the asset. Any gain or loss arising on derecognition of the asset (calculated as the difference between the net disposal proceeds and the carrying amount of the item) is included in the income statement in the period in which the item is derecognised.

1.8 OTHER PROPERTY, PLANT AND EQUIPMENT Items of property, plant and equipment are recognised at cost and are subsequently carried at their historical cost less any accumulated depreciation and any accumulated impairment losses.

1.9 DEPRECIATION Property, plant and equipment, other than assets related to exploration and production of mineral resources, is depreciated using the straight line method over the following useful lives:

Main depreciation periods (years)

Office and computer equipment 3 to 5 years

Freehold and leasehold improvements up to 50 years

Plant and machinery 5 to 40 years

50



1.10 IMPAIRMENT OF PROPERTY, PLANT AND EQUIPMENT AND INTANGIBLE ASSETS INCLUDING GOODWILLIn accordance with IAS 36, impairment tests are carried out on items of property, plant and equipment and intangible assets where there is an indication that the assets may be impaired. Such indications may be based on events or changes in the market environment, or on internal sources of information.

Impairment indicatorsProperty, plant and equipment and intangible assets with finite useful lives are only tested for impairment when there is an indication that they may be impaired. This is generally the result of significant changes to the environment in which the assets are operated or when asset performance is worse than expected.

The main impairment indicators used by the Group are described below:

• external sources of information:

– significant changes in the economic, technological, political or market environment in which the entity operates or to which an asset is dedicated;

– fall in demand; and

– changes in energy prices and exchange rates.

• internal sources of information:

– evidence of obsolescence or physical damage not budgeted for in the depreciation/amortisation schedule;

– worse-than-expected production or cost performance;

– reduction in reserves and resources, including as a result of unsuccessful results of drilling operations;

– pending expiry of licence or other rights; and

– in respect of capitalised exploration and evaluation costs, lack of planned future activity on the prospect or licence.

Measurement of recoverable amountIn order to review the recoverable amount in an impairment test, the assets are grouped, where appropriate, into CGUs and the carrying amount of each unit is compared with its recoverable amount.

For operating entities which the Group intends to hold on a long-term and going concern basis, the recoverable amount of an asset corresponds to the higher of its fair value less costs to sell and its value in use. Value in use is primarily determined based on the present value of future operating cash flows. Standard valuation techniques are used based on the discount rates based on the specific characteristics of the operating entities concerned; discount rates are determined on a post-tax basis and applied to post-tax cash flows. The recoverable amounts calculated on the basis of these discount rates are the same as the amounts obtained by applying the pre-tax discount rates to cash flows estimated on a pre-tax basis, as required by IAS 36.

Any impairment loss is recorded in the consolidated income statement under ‘Impairment losses’.

Impairment losses recorded in relation to property, plant and equipment may be subsequently reversed if the recoverable amount of the assets subsequently increases above carrying value. The increased carrying amount of an item of property, plant or equipment attributable to a reversal of an impairment loss may not exceed the carrying amount that would have been determined (net of depreciation/amortisation) had no impairment loss been recognised in prior periods. Impairment losses in respect of intangible assets may not be reversed on a future change in circumstances that led to the impairment.

GoodwillGoodwill is not amortised but is reviewed for impairment at least annually. For the purpose of impairment testing, goodwill is allocated to each of the Group’s CGUs expected to benefit from the business combination. Country groups of CGUs to which goodwill has been allocated are tested for impairment annually, or more frequently when there is an indication the unit may be impaired. If the recoverable amount of the group of CGUs is less than the carrying amount of the unit, the impairment loss is allocated first to reduce the carrying amount of any goodwill allocated to the unit and then to the other assets of the unit pro rata on the basis of the carrying amount of each asset in the unit. An impairment loss recognised for goodwill is not reversed in a subsequent period.

On disposal of a subsidiary, the attributable amount of goodwill is included in the determination of the profit or loss on disposal.

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1.11 LEASESThe Group holds assets for its various activities under lease contracts as set out in IAS 17.

Payments made under operating leases are recognised as an expense on a straight line basis over the lease term.

1.12 INVENTORIESInventories of equipment and materials are measured at the lower of cost and net realisable value. Cost is determined based on the first-in, first-out method or the weighted average cost formula.

An impairment loss is recognised when the net realisable value of inventories is lower than their weighted average cost.

Hydrocarbon inventories are stated at net realisable value with movements in value recognised in the profit and loss account. Net realisable value corresponds to the estimated selling price in the ordinary course of business, less the estimated costs of completion and the estimated costs necessary to make the sale.

See also 1.19 ‘Revenue’, regarding volumes of under and over lifted entitlement to production.

1.13 FINANCIAL INSTRUMENTSFinancial instruments are recognised and measured in accordance with IFRS 9.

1.14 FINANCIAL ASSETSFinancial assets comprise loans and receivables carried at amortised cost, including trade and other receivables, hedging derivatives, and financial assets measured at fair value through income, including certain derivative financial instruments. Financial assets are analysed into current and non-current assets in the consolidated statement of financial position.

Loans and receivables carried at amortised costThis item primarily includes loans and advances to associates or non-consolidated companies, guarantee deposits, trade and other receivables.

On initial recognition, these loans and receivables are recorded at fair value plus transaction costs. At each statement of financial position date, they are measured at amortised cost using the effective interest rate method.

Leasing guarantee deposits are recognised at their nominal value.

On initial recognition, trade and other receivables are recorded at fair value, which generally corresponds to their nominal value. Impairment losses are recorded based on the estimated risk of non-recovery. Trade receivables are stated net of provisions. The Group has used the simplified approach in calculating expected credit losses for trade receivables that do not contain a significant financing component. The Group applies the practical expedient to calculate expected credit losses using a provision matrix considering how current and forward-looking information may affect our customers’ historical default rates and, consequently, how the information would affect their current expectations and estimates of expected credit losses.

Financial assets are derecognised when the rights to receive cash flows from the financial assets have expired or have been transferred and the entity has transferred substantially all the risks and rewards of ownership. If the entity neither retains nor transfers substantially all the risks and rewards, but has not retained control of the financial assets, it also derecognises the assets.

1.15 DERIVATIVES AND HEDGE ACCOUNTING – ASSETS AND LIABILITIESDerivative financial instruments are contracts: (i) whose value changes in response to the change in one or more observable variables; (ii) that do not require any material initial net investment; and (iii) that are settled at a future date. Derivative instruments include swaps, options, futures and swaptions, as well as forward commitments to purchase or sell listed and unlisted securities, and firm commitments or options to purchase or sell non-financial assets that involve physical delivery of the underlying.

The Group uses derivative financial instruments to manage and reduce its exposure to market risks arising from fluctuations in interest rates, foreign currency exchange rates and commodity prices, mainly for oil and gas. The use of derivative instruments is governed by a Group policy for managing interest rate, currency and commodity risks.

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The Group’s hedging policy is to ensure that in relation to its debt facilities and the borrowing base assets, the Group has:

(a) appropriate controls governing its use of financial derivative transactions; and

(b) a prudent and cost efficient approach to mitigating its exposure to fluctuations in:

(i) commodity prices in energy markets; and

(ii) foreign exchange and interest rates in capital markets.

Hedging instruments: recognition and presentationDerivative instruments qualifying as hedging instruments are recognised in the consolidated statement of financial position within current assets or liabilities if expiry is less than 12 months, or as non-current items if expiring after 12 months and measured at fair value.

Cash flow hedgesA cash flow hedge is a hedge of the exposure to variability in cash flows that could affect the Group’s profit or loss. The hedged cash flows may be attributable to a particular risk associated with a recognised financial or non-financial asset or a highly probable forecast transaction.

The portion of the gain or loss on the hedging instrument that is determined to be an effective hedge is recognised directly in other comprehensive income (OCI), net of tax, while the ineffective portion is recognised in net income. The gains or losses accumulated in OCI are reclassified to the consolidated income statement under the same caption as the loss or gain on the hedged item – i.e., within current operating income for operating cash flows and financial income or expenses for other cash flows – in the same periods in which the hedged cash flows affect profit or loss.

If the hedging relationship is discontinued, the cumulative gain or loss on the hedging instrument remains recognised in OCI until the forecast transaction occurs. However, if a forecast transaction is no longer expected to occur, the cumulative gain or loss on the hedging instrument is immediately recognised in net income.

Identification and documentation of hedging relationshipsThe hedging instruments and hedged items are designated at the inception of the hedging relationship. The hedging relationship is formally documented in each case, specifying the risk management strategy, risk management objective, the hedged risk, sources of hedge ineffectiveness and the methods used to assess hedge effectiveness. Sources of hedge ineffectiveness include mismatch in payment dates and off market hedges for acquired hedges. Only derivative contracts entered into with external counterparties are considered as being eligible for hedge accounting.

The Group establishes its hedge ratio by considering hedging items as a proportion of post-tax production. Hedge effectiveness is assessed and documented at the inception of the hedging relationship and on an ongoing basis throughout the periods for which the hedge was designated. Hedge effectiveness is demonstrated prospectively using various methods, based mainly on a qualitative assessment of the critical terms of the hedging instrument and the hedged item as to whether their values will generally move in the opposite direction because of the same risk being hedged. Methods based on a regression analysis of statistical correlations between historical price data are also used.

Upon the designation of option instruments as hedging instruments, the intrinsic and time value components are separated, with only the intrinsic component being designated as the hedging instrument and the time value component is deferred in OCI as a cost of hedging.

Derivative instruments not qualifying for hedge accounting: recognition and presentationThese items mainly include derivative financial instruments used in economic hedges that have not been – or are no longer – documented as hedging relationships for accounting purposes.

When a derivative financial instrument does not qualify or no longer qualifies for hedge accounting, changes in fair value are recognised directly in net income, under ‘Mark-to-market on commodity contracts other than hedging instruments’, below the current operating income, for derivative instruments with non-financial assets as the underlying, and in financial income or expenses for currency, interest rate and equity derivatives.

Derivative instruments not qualifying for hedge accounting and other derivatives expiring in less than 12 months are recognised in the consolidated statement of financial position in current assets and liabilities, while derivatives expiring after this period are classified as non-current items.

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Fair value measurementThe fair value of instruments listed on an active market is determined by reference to the market price. In this case, these instruments are presented in level 1 of the fair value hierarchy.

The fair value of unlisted financial instruments for which there is no active market, and for which observable market data exist, is determined based on valuation techniques such as option pricing models or the discounted cash flow method.

Models used to evaluate these instruments take into account assumptions based on market inputs:

• the fair value of interest rate swaps is calculated based on the present value of future cash flows. Cash flows are discounted using standard valuation techniques and observable market-based inputs, including interest rate curves, having regard to the timing of the cash flows; and

• commodity derivatives contracts are valued by reference to observable market-based inputs based on the present value of future cash flows (commodity swaps or commodity forwards) or option pricing models (options), which factor in market price volatility. Contracts with maturities exceeding the depth of transactions for which prices are observable, or which are particularly complex, may be valued based on internal assumptions.

These instruments are presented in level 2 of the fair value hierarchy except when the evaluation is based mainly on data that are not observable; in this case they are presented in level 3 of the fair value hierarchy.

Equity investments are valued using the market approach based on a multiple of EBITDA consistent with the valuation obtained for transactions involving investments similar in nature.

To comply with the provisions of IFRS 13, the Group incorporates credit valuation adjustments to reflect appropriately both its own non-performance risk and the respective counterparty’s non-performance risk in the fair value measurements. In adjusting the fair value of its derivative contracts for the effect of non-performance risk, the Group has considered the impact of netting and any applicable credit enhancements, such as collateral postings, thresholds, mutual puts, and guarantees.

Equity investments held at fair value through OCIWhere the Group holds an equity investments primarily for strategic purposes, the Company may on initial recognition elect to recognise any change in the fair value through OCI. Under this method, changes in the valuation of the investment are never reclassified to profit and loss, even if the asset is impaired, sold or otherwise derecognised. Where the Company holds an equity investment that is not for strategic purposes, following its initial recognition, any subsequent change in the valuation is recognised through fair value profit and loss.

1.16 FINANCIAL LIABILITIESFinancial liabilities include borrowings, trade and other payables, derivative financial instruments and other financial liabilities.

Financial liabilities are broken down into current and non-current liabilities in the consolidated statement of financial position. Current financial liabilities primarily comprise:

• financial liabilities with a settlement or maturity date within 12 months after the reporting date;

• financial liabilities in respect of which the Group does not have an unconditional right to defer settlement beyond 12 months after the reporting date;

• derivative financial instruments qualifying as fair value hedges where the underlying is classified as a current item (see note 1.15); and

• commodity trading derivatives not qualifying as hedges (see note 1.15).

Measurement of borrowingsBorrowings are measured at amortised cost using the effective interest rate method. On initial recognition, any issue or redemption premiums and discounts and issuing costs are added to/deducted from the nominal value of the borrowings concerned. These items are taken into account when calculating the effective interest rate and are therefore recorded in the consolidated income statement over the life of the borrowings using the amortised cost method.

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1.17 CASH AND CASH EQUIVALENTSCash and cash equivalents in the statement of financial position comprise cash at banks and on hand, short-term deposits with a maturity of three months or less and highly liquid investments which are subject to an insignificant risk of changes in value. For the purpose of the consolidated statement of cash flows, cash and cash equivalents consist of cash and short-term deposits, as defined above, net of outstanding bank overdrafts, as they are considered an integral part of the Group’s cash management.

1.18 PROVISIONS1.18.1 GeneralProvisions are recognised when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and the amount of the obligation can be estimated reliably.

Provisions are reviewed at the end of each reporting period and adjusted to reflect the current best estimate. If it is no longer probable that an outflow of economic resources will be required to settle the obligation, the provision is reversed. If the effect of the time value of money is material, provisions are discounted using a current pre-tax rate that reflects, where appropriate, the risks specific to the liability. When discounting is used, the increase in the provision due to the passage of time is recognised as a finance cost.

1.18.2 Provisions for post-employment benefit obligations and other long term employee benefits Depending on the laws and practices in force in the countries where the Group operates, Group companies have obligations in terms of pensions, early retirement payments, retirement bonuses and other post-employment benefit plans.

The Group’s obligations in relation to pensions and other employee benefits are recognised and measured in compliance with IAS 19. Accordingly:

• the cost of defined contribution plans is expensed based on the amount of contributions payable in the period; and

• the Group’s obligations concerning pensions and other employee benefits payable under defined benefit plans are assessed on an actuarial basis using the projected unit credit method. These calculations are based on assumptions relating to mortality, staff turnover and estimated future salary increases, as well as the economic conditions specific to each country or subsidiary of the Group. Discount rates are determined by reference to the yield, at the measurement date, on high-quality corporate bonds in the related geographical area (or on government bonds in countries where no representative market for such corporate bonds exists).

Provisions are recorded when commitments under these plans exceed the fair value of plan assets. Where the value of plan assets (capped where appropriate) is greater than the related commitments, the surplus is recorded as an asset under ‘Other assets’ (current or non-current).

As regards post-employment benefit obligations, actuarial gains and losses are recognised in other comprehensive income. Where appropriate, adjustments resulting from applying the asset ceiling to net assets relating to overfunded plans are treated in a similar way. However, actuarial gains and losses on other long-term benefits such as long-service awards, are recognised immediately in income.

Net interest on the net defined benefit liability (asset) is presented in net financial expense (income).

1.18.3 Decommissioning costsA provision is recognised when the Group has a present legal or constructive obligation to plug wells, dismantle facilities or to restore a site. An asset is recorded simultaneously by including this decommissioning obligation in the carrying amount of the facilities concerned. Adjustments to the provision due to subsequent changes in the expected outflow of resources, the decommissioning date or the discount rate are deducted from or added to the cost of the corresponding asset. The impact of unwinding the discount (accretion) is recognised in financial expenses for the period.

Provisions with a maturity of over 12 months are discounted when the effect of discounting is material. The discount rate (or rates) used reflect current market assessments of the time value of money, based on the relevant risk-free rate, adjusted if appropriate for any risks specific to the liability concerned.

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1.19 REVENUERevenue is recognised when the Group satisfies a performance obligation by transferring oil and gas to a customer. The title to oil and gas typically transfers to a customer at the same time as the customer takes physical possession of the commodity, which is when the performance obligation is fully satisfied.

Differences may arise in a joint operation between the Group’s share of production entitlement from an oil or gas field and the volume which has been lifted and sold. Such ‘under or over lift’ entitlements are recognised in current assets or liabilities, respectively, at net realisable value, with a corresponding adjustment through production costs. As a result, the reported operating result for each period reflects the Group’s share of saleable production in that period.

The Group recognises its share of LNG revenues in respect of its Indonesian production sharing contracts based on its contractual entitlement under the contract. Revenues include volumes allocated to the Group for sale as reimbursement of costs of operation of the LNG processing facility, with corresponding costs included as operating expenses.

Further information regarding segmental analysis is contained in note 4.

1.20 CONSOLIDATED STATEMENT OF CASH FLOWS The consolidated statement of cash flows is prepared using the indirect method starting from profit before tax.

‘Interest received on non-current financial assets’ is classified within investing activities because it represents a return on investments. ‘Interest received on cash and cash equivalents’ is shown as a component of financing activities because the interest can be used to reduce borrowing costs. This classification is consistent with the Group’s internal organisation, where debt and cash are managed centrally by the treasury department.

Cash flows relating to the payment of income tax are presented on a separate line of the consolidated statement of cash flows.

1.21 TAXATIONCurrent tax, including corporation tax and foreign tax is provided at amounts expected to be paid (or recovered) using the tax rates and laws that have been enacted or substantively enacted by the balance sheet date. Tax is recognised in the income statement, except to the extent that it relates to items recognised directly in equity. In this case, the tax is recognised in equity. Management periodically evaluates positions taken in the tax returns with respect to situations in which applicable tax regulations are subject to interpretation and establishes provisions where appropriate.

Deferred tax is recognised in respect of all temporary differences identified at the balance sheet date, except to the extent that the deferred tax arises from the initial recognition of goodwill or the initial recognition of an asset or liability in a transaction which is not a business combination and at the time of the transaction affects neither accounting profit nor taxable profit and loss. Temporary differences are differences between the carrying amount of the Company’s assets and liabilities and their tax base. Deferred tax assets are recognised only to the extent that the deductible temporary differences will reverse in the future and it is probable that there will be sufficient taxable profit available against which the temporary differences can be utilised. The amount of deferred tax provided is using tax rates that have been enacted or substantively enacted at the balance sheet date. Deferred taxes are reviewed at least annually at the end of the financial year to take into account factors including the impact of changes in tax laws and the prospects of recovering deferred tax assets arising from deductible temporary differences. Deferred tax assets and liabilities are not discounted.

Current and deferred income tax expense for interim periods is calculated at the level of each tax entity by applying the average estimated annual effective tax rate for the current year to the taxable income for the interim period, with the exception of significant exceptional items. Significant exceptional items, if any, are recognised using their specific applicable taxation rates.

1.22 CASH DIVIDENDThe Group and Company recognises a liability to pay a dividend when the distribution is authorised and the distribution is no longer at the discretion of the Group and Company. As per the corporate laws of England and Wales, a distribution is authorised when it is approved by the shareholders. A corresponding amount is recognised directly in equity.

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2. Financial risk managementGroup financial risk factorsThe Group’s activities expose it to a variety of financial risks: market risk (e.g. currency risks), credit risk and liquidity risk. The Group’s overall risk management programme focuses on the unpredictability of financial markets and seeks to minimise potential adverse effects on the Group’s financial performance.

Market risk (foreign exchange risk) The Group operates internationally and is therefore exposed to foreign exchange risk arising from various currency exposures, primarily with respect to the Pound Sterling (GBP), Norwegian Krone (NOK) and Euros (EUR). Foreign exchange risk arises from future commercial transactions, recognised assets and liabilities and net investments in foreign operations.

Credit risk Currently credit risk only arises from cash and cash equivalents, sales receivables and hedging derivatives. For banks and financial institutions, only independently rated parties with a minimum rating of ‘BBB’ are accepted.

Liquidity risk Liquidity risk is the risk that the Group might not have sources of funding to meet its business needs. The Directors believe that the Group has sufficient cash, undrawn committed funds under its borrowing base facility and expected sources of liquidity to meet the business’s forecast requirements.

3. Revenue from contracts with customers Set out below is the reconciliation of the revenue from contracts with customers with the amounts disclosed in note 4.

2018

Group In millions of $

Production revenue Other Total

External customers 2,511.7 26.2 2,537.9

TOTAL GROUP REVENUE 2,511.7 26.2 2,537.9

There are no right of return assets and refund liabilities held within the Group and costs to obtain contracts are negligible.

In 2017, the Group and Company revenue was $nil.

3.1 PERFORMANCE OBLIGATIONSOil and gas salesThe performance obligation is satisfied by the delivery of the product at an agreed delivery point in the distribution chain, often either at the well head or delivery terminal. Payment is generally due within 30 days from delivery or offtake but can be as much as 90 days. Variation in the specification of the product is reflected in the contract price as an increase or decrease against a quoted benchmark product such as Brent (oil) or NTS (gas).

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4. Segmental information 4.1 SEGMENTAL ANALYSISNeptune Energy’s reportable segment is that used by the Group’s Board and management to run the business. The Board is responsible for allocating resources and assessing performance of the segment.

The Group’s activities consist of a single class of business (upstream), representing the acquisition, exploration, development and production of the Group’s own oil and gas reserves and resources and is focused on seven geographical regions; UK, Norway, Netherlands, Germany, North Africa, Asia Pacific and Corporate.

Year ended 31 December 2018


31 December2017

GroupIn millions of $ UK Norway Netherlands Germany

North Africa

Asia Pacific Corporate

2018Total

2017Total

Production revenue by origin 219.2 1,172.0 358.2 192.5 40.0 529.8 – 2,511.7 –

Other revenue 5.2 0.6 13.2 7.2 – – – 26.2 –

REVENUE 224.4 1,172.6 371.4 199.7 40.0 529.8 – 2,537.9 –

CURRENT OPERATING INCOME 96.8 801.5 132.2 8.7 3.4 223.2 (152.0) 1,113.8 (3.7)

Share of net income from investments using equity method 4.0 –

NET OPERATING PROFIT AFTER EQUITY ACCOUNTED INVESTMENTS 1,117.8 (3.7)

Mark-to-market on commodity contracts other than trading instruments (46.4)

Restructuring release 2.8 –

Acquisition transaction costs (62.9) –

Release of EPI deferred consideration 21.0 –

Other gains 17.0 –

PROFIT BEFORE FINANCIAL ITEMS 1,049.3 (3.7)

Finance income 6.5 (0.1)

Financial costs (149.7) –

PROFIT BEFORE TAX 906.1 (3.8)



31 December2017

In millions of $ UK Norway Netherlands GermanyNorth Africa

Asia Pacific Corporate Total Total

EBITDAX 184.6 1,088.7 287.9 76.7 15.2 431.8 (200.9) 1,884.0 –

Included in revenue from external customers are revenues of approximately $529.0 million and $465.0 million relating to Group’s customers who each contribute more than 10 per cent of total sales revenue (2017: $nil). As sales of oil and gas are made on global markets and are highly liquid, the Group does not place reliance on the largest customers mentioned above.

All activities in 2017 resided in Corporate.

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31 December2017



BALANCE SHEET

Assets 1,020.3 2,398.6 698.3 553.7 619.6 1,324.9 135.3 6,750.7 0.8

Liabilities (249.1) (1,353.6) (845.1) (601.5) (29.3) (230.9) (1,754.3) (5,063.8) (4.6)

NET ASSETS 771.2 1,045.0 (146.8) (47.8) 590.3 1,094.0 (1,619.0) 1,686.9 (3.8)

Corporate net liabilities includes amounts of a Corporate nature and not specifically attributable to a reportable segment. The liabilities comprise the Group’s external debt and other non-attributable corporate liabilities.

In 2017, all of the net assets of the Group resided in Corporate.

Capital investment In 2017, all of the capital expenditure resided in Corporate and there were no investments accounted under the equity method.



31 December2017



Investments accounted under the equity method – – 29.3 – 511.5 – – 540.8 –

Capital expenditure 116.1 184.3 32.5 79.6 11.3 31.7 1.8 457.3 –

116.1 184.3 61.8 79.6 522.8 31.7 1.8 998.1 –

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5. Business combinations 5.1 ACQUISITION OF ENGIE E&P INTERNATIONAL SAOn 15 February 2018, the Group acquired 100 per cent of the voting shares of ENGIE E&P International S.A. (EPI) (now renamed Neptune Energy International S.A.), an unlisted company based in France which was the holding company of a group involved internationally in oil and gas exploration and production. The acquisition sees the Group become an international independent E&P business across the North Sea, North Africa and the Asia Pacific region. The acquisition has been accounted for using the acquisition method. The consolidated financial statements include the results of EPI from the acquisition date of 15 February 2018 to 31 December 2018.

The fair values of the identifiable assets and liabilities of EPI as at the date of acquisition were:

EPI acquisition balance sheetIn millions of $

Fair value recognised on acquisition

NON-CURRENT ASSETS

Exploration and evaluation assets 67.0

Other intangible assets 37.9

Property, plant and equipment 4,079.8

Derivative instruments 47.6

Investments in entities accounted for using the equity method 523.1

Other non-current assets 17.7

Equity instruments 24.3

Deferred tax assets 491.7

TOTAL NON-CURRENT ASSETS 5,289.1

CURRENT ASSETS

Derivative instruments 2.9

Trade and other receivables 429.9

Inventories 58.2

Other current assets 328.4

Cash and cash equivalents 68.8

TOTAL CURRENT ASSETS 888.2

TOTAL ASSETS 6,177.3


Provisions (1,698.5)

Long-term borrowings (187.2)

Derivative instruments (32.1)

Other non-current liabilities (215.3)

Deferred tax liabilities (698.9)

TOTAL NON-CURRENT LIABILITIES (2,832.0)

CURRENT LIABILITIES

Provisions (15.9)

Derivative instruments (72.0)

Trade and other payables (165.2)

Income taxes payable (193.9)

Other current liabilities (230.3)

TOTAL CURRENT LIABILITIES (677.3)

TOTAL IDENTIFIABLE NET ASSETS AT FAIR VALUE 2,668.0

Goodwill arising on acquisition 627.0

PURCHASE CONSIDERATION 3,295.0

ANALYSIS OF CASH FLOWS ON CONSIDERATION

Net cash acquired with the subsidiary (included in cash flows from investing activities) 68.8

Purchase consideration (3,295.0)

Contingent consideration 21.0

NET CASH FLOW ON ACQUISITION (3,205.2)

Purchase consideration comprised cash and cash equivalents of $3,256.5 million and contingent consideration of $38.5 million.

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From the date of acquisition, the acquisition has contributed revenue of $2,513.8 million from the continuing operations of the Group and net profit of $259.9 million before any adjustment to finance costs. If the acquisition had taken place at the beginning of the year, revenue from continuing operations would have been $2,771.7 million and net profit $315.6 million.

The goodwill recognised arises principally as a result of recognition of deferred tax liabilities for the temporary difference between assigned fair values of oil and gas properties, which are based on post-tax values, and their tax base. The goodwill is not deductible for income tax purposes.

Transaction costs of $60.4 million have been expensed in the consolidated income statement and are part of operating cash flow in the statement of cash flows.

Contingent considerationIncluded in the purchase consideration at acquisition was $38.5 million which would be payable based upon satisfaction of certain project milestones. No contingent consideration was payable if the milestones were not achieved. The reversal of contingent consideration of $21 million previously recognised on the statement of financial position has been released to the income statement in the period as an adjustment to fair value through the profit and loss.

All contingent consideration has been settled for a total cost of $17.5 million.

5.2 ACQUISITION OF VNG NORGE ASOn 28 September 2018, the Group acquired 100 per cent of the voting shares of VNG Norge AS (an unlisted company based in Norway) from its parent VNG AG (a German natural gas and energy service provider).

VNG Norge AS has a portfolio of 42 licences, five producing fields and three development projects including: in Norway, the Fenja oil development (30 per cent and operator), Bauge (2.5 per cent); and in Denmark, Solsort (13.8 per cent). The VNG Norge asset base is highly complementary to Neptune’s existing Norwegian portfolio. The fair values of the identifiable assets and liabilities of VNG Norge AS as at the date of acquisition were:

In millions of $Fair value recognised

on acquisition

NON-CURRENT ASSETS

Intangible assets 11.9

Property, plant and equipment 293.1

Deferred tax asset 117.1

TOTAL NON-CURRENT ASSETS 422.1

CURRENT ASSETS

Trade and other receivables 56.4

Inventories –

Cash and cash equivalents 71.2

TOTAL CURRENT ASSETS 127.6

TOTAL ASSETS 549.7


Provisions (112.4)

TOTAL NON-CURRENT LIABILITIES (112.4)

CURRENT LIABILITIES

Trade and other payables (1.2)

Other current liabilities (80.0)

TOTAL CURRENT LIABILITIES (81.2)

TOTAL IDENTIFIABLE NET ASSETS AT FAIR VALUE 356.1

Goodwill arising on acquisition (provisional) 80.7

PURCHASE CONSIDERATION 436.8

ANALYSIS OF CASH FLOWS ON CONSIDERATION

Net cash acquired with the subsidiary (including cash flows from investing activities) 71.2

Purchase consideration (436.8)

Contingent consideration outstanding 24.3

NET CASH FLOW ON ACQUISITION (341.3)

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Purchase consideration comprised cash of $412.5 million and contingent consideration of $24.3 million.

The acquisition has contributed $24.1 million revenue from the continuing operations of the Group and net profit of $1.6 million before any adjustment to finance costs. If the acquisition had taken place at the beginning of the year, revenue from continuing operations would have been increased by $65.4 million and net profit increased by $5.6 million.

The goodwill recognised arises principally as a result of recognition of deferred tax liabilities for the temporary difference between assigned fair values of oil and gas properties, which are based on post-tax values, and their tax base. The goodwill is not deductible for income tax purposes.

Transaction costs of $2.5 million have been expensed in the consolidated statement of profit and loss and are part of operating cash flow in the statement of cash flows.

Contingent considerationIncluded in the purchase consideration at acquisition was $24.3 million which would be payable based upon satisfaction of certain tests linked to project success factors and milestones. No contingent consideration is payable if the tests are not achieved. No fair value adjustment to this contingent consideration was required in the period ended 31 December 2018.

The possible outcome for contingent consideration ranges from $nil to $50 million.

The fair values recognised on acquisition are provisional at year ended 31 December 2018. The accounting for the business combination will be completed in 2019 taking into account any measurement period adjustments that may arise.

6. Operating profit/(loss) before taxationIncluded within the Group’s operating profit/(loss) before taxation were the following items:

In millions of $31 December

201831 December

2017

COST OF SALES

Movements in over/under lift balances 0.4 –

Production, insurance and transportation costs 503.4 –

Depreciation of property, plant and equipment 649.0 –

Amortisation of intangible assets 7.0 –

Other operating costs 43.5 –

EXPLORATION EXPENSES

Exploration and evaluation expenditure 81.5 –

Unsuccessful exploration expenditure written off 7.7 –

GENERAL AND ADMINISTRATION EXPENSE INCLUDE

Employee costs 89.0 0.5

Auditor’s remuneration – The parent company 2.0 0.1

Subsidiary companies 0.4 –

Non-audit fees 1.1 –

Operating lease payments 10.5 0.2

Ernst & Young LLP has served as Neptune Energy’s independent external auditor for the two-year period ended 31 December 2018. The external auditor is subject to reappointment at the year-end Board meeting and have been reappointed for the 2019 period end. The audit of financial statement costs totalled $19,200 for the parent company audit. The 2017 auditor’s remuneration was $13,491 for the parent company and $13,491 for subsidiary entities.

7. Staff costs In millions of $

31 December2018

31 December2017

Wages and salaries 152.5 0.4

Social security costs 13.5 0.1

Pension costs 23.1 –

TOTAL 189.1 0.5

The average number of persons employed during the year (including Directors) was 1,383 (2017: nil).

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7.1 TOTAL DIRECTORS’ REMUNERATIONThe total Directors’ remuneration is:


201831 December

2017

Short term employee benefits 6.7 0.4

Other long term benefits – –

TOTAL 6.7 0.4

Highest paid Directors’ remunerationIn millions of $

31 December2018

31 December2017


Other long term benefits – –

TOTAL 3.2 0.4

8. Other operating losses/(gains)GroupIn millions of $

31 December2018

31 December2017

Mark-to-market on commodity contracts other than trading instruments:

Loss/(gain) on commodity derivative instruments at fair value through profit and loss 31.2 –

Loss/(gain) on foreign exchange forward at fair value through profit and loss 12.0 –

Loss/(gain) on ineffectiveness on commodity contracts designated as hedges 2.4 –

Loss/(gain) on excluded components on commodity contracts designated as hedges 1.2 –

Loss/(gain) on excluded components on interest rate swaps designated as hedges (0.4) –

Loss/(gain) on equity investments at fair value through profit and loss (1.2) –

Restructuring provision release (2.8) –

Business combination transaction costs 62.9 –

EPI deferred consideration release (21.0) –

Other gains (15.8) –

TOTAL 68.5 –

9. Finance income and costs9.1 FINANCE INCOME

31 December2018

Period from 22 March to

31 December2017


Bank interest income 6.1 –

Net foreign exchange gains 0.4 –

TOTAL FINANCE INCOME 6.5 –

9.2 FINANCE COST

31 December2018

Period from 22 March to

31 December2017


Interest expense 106.7 –

Commitment fees 12.1 –

Unwinding of discount on decommissioning and other provisions 30.9 –

TOTAL FINANCE COSTS 149.7 –

In the period to 31 December 2017, the interest expense was $36,439 and there was a foreign exchange loss of $57,024.

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10. Dividend



2018


31 December 2017

Aggregate amount of dividends paid in the year 380.0 –

Aggregate amount of dividends liable to pay at the balance sheet date – –

Company In millions of $


2018


31 December 2017

Aggregate amount of dividends paid in the year 380.0 –

Aggregate amount of dividends liable to pay at the balance sheet date – –

On the 18 December 2018, the Company paid an interim dividend of 19.22 cents per fully paid ordinary share registered on the register of shareholders on that date for a total cost of $380.0 million (2017: $nil) to its immediate and ultimate parent undertaking.

No final dividend is proposed (2017: $nil).

11. TaxationThe major components of income tax expense in the consolidated income statement are:


Yearended

31 December2018


31 December 2017

Current taxation 567.1 –

Deferred taxation 77.5 –

TOTAL INCOME TAX EXPENSE RECOGNISED IN INCOME STATEMENT 644.6 –

The effective tax rate for the Group for 2018 was 71 per cent.

11.1 RECONCILIATION BETWEEN THEORETICAL INCOME TAX EXPENSE AND ACTUAL TAX EXPENSEGroupIn millions of $

31 December2018

31 December2017

PROFIT/(LOSS) BEFORE TAXATION 906.1 (3.8)

Expected weighted average statutory tax rate 71% 19%

Expected tax charge/(credit) at weighted average statutory rate 646.2 (0.7)

EFFECTS ON TAX CHARGE OF:

Income subject to tax at different statutory rates 0.7 –

Non tax-deductible expenditure 0.3 –

Income not subject to taxation (3.7) –

Utilisation of previously unrecognised deferred tax assets (5.3) –

Adjustments in respect of prior periods 9.6

(Recognition)/derecognition of deferred tax assets (43.6)

Non-recognition of deferred tax assets 39.6 0.7

Other items 0.8 –

TOTAL INCOME TAX CHARGE/(CREDIT) 644.6 –

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11.2 ANALYSIS OF DEFERRED TAX INCOME/EXPENSE RECOGNISED IN OTHER COMPREHENSIVE INCOME, BY TYPE OF TEMPORARY DIFFERENCE


31 December2018

31 December2017

DIFFERENCE TYPE

Actuarial gains and losses 2.5 –

Cash flow hedges 3.3 –

NET DEFERRED TAX INCOME/(EXPENSE) 5.8 –

11.3 CHANGES IN DEFERRED TAXESThe net movement in deferred tax assets and (liabilities) is shown below:

GroupIn millions of $ PP&E

Retirement obligations Pensions Tax losses Other Total

AS AT 1 JANUARY 2018 – – – – – –

Business combination – ENGIE E&P International S.A. (744.2) 176.7 44.3 377.2 (61.0) (207.0)

Business combination – VNG Norge AS (121.5) 87.0 – 81.6 69.9 117.0

Credit/(charge) for the year 79.2 64.9 (4.8) (120.3) (96.5) (77.5)

Charge to equity and other comprehensive income – – – – 5.8 5.8

Currency translation adjustment (75.3) 21.3 3.9 31.5 36.7 18.1

AS AT 31 DECEMBER 2018 (861.8) 349.9 43.4 370.0 (45.1) (143.6)

There were no net deferred tax assets and liabilities recognised in the Company for 2018 or 2017.

11.4 TEMPORARY DIFFERENCES FOR WHICH NO DEFERRED TAX ASSET HAS BEEN RECOGNISED


31 December2018

31 December2017

Unused tax losses 2,908.0 –

TOTAL TEMPORARY DIFFERENCE FOR WHICH NO DEFERRED TAX ASSET IS RECOGNISED 2,908.0 –

Of the above unrecognised deductible temporary differences, $2,886.2 million are not subject to time limits for utilisation.

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12. Goodwill GroupIn millions of $ 2018 2017

COST AND NET BOOK VALUE AT 1 JANUARY – –

Business combination – ENGIE E&P International S.A. 627.0 –

Business combination – VNG Norge AS 80.7 –

Currency translation adjustments (60.9) –

COST AND NET BOOK VALUE AT 31 DECEMBER 646.8 –

The goodwill arose on the acquisition on 15 February 2018 of ENGIE E&P International S.A. (EPI) (now renamed Neptune Energy International S.A.), an unlisted company based in France which was the holding company of a group involved internationally in oil and gas exploration and production. Further goodwill arose on the acquisition on 28 September 2018 of VNG Norge AS (an unlisted company based in Norway) from its parent VNG AG (a German natural gas and energy service provider).

The goodwill from these business combinations is reviewed for impairment prospectively at each reporting date, or earlier if there are indications of impairment. For the purpose of impairment testing, goodwill is allocated to groups of cash-generating units; these represent the lowest level at which goodwill is monitored. The recoverable amounts are determined based on value-in-use calculations. The key assumptions in estimating the recoverable amounts are disclosed in note 1.3.1.

The goodwill assigned to Norway is $554.6 million. The headroom between the recoverable amount and the carrying amount of the Norway group of cash-generating units is $771.5 million. The discount rate applied in determining the recoverable amount was 8 per cent.

No reasonable possible change in any of the key assumptions would cause the asset’s carrying amount to exceed its recoverable amount.

The remaining goodwill is assigned to the Netherlands, Germany and Egypt group of cash-generating units. The carrying amount of the goodwill allocated to these cash-generating units is not significant in comparison with the Group’s total goodwill.

13. Intangible assetsGroup In millions of $

Exploration and

evaluation Other Total

COST AT 1 JANUARY 2018

Business combinations 78.8 37.9 116.7

Additions 16.7 3.0 19.7

Unsuccessful exploration expenditure (7.7) – (7.7)

Transfers to property, plant and equipment (3.9) – (3.9)

Currency translation adjustments (2.3) (3.3) (5.6)

COST AT 31 DECEMBER 2018 81.6 37.6 119.2

AMORTISATION AS AT 1 JANUARY 2018

Charge for the year – (7.0) (7.0)

Currency translation adjustments – 0.3 0.3

AMORTISATION AT 31 DECEMBER 2018 – (6.7) (6.7)

NET BOOK VALUE AT 31 DECEMBER 2018 81.6 30.9 112.5

There were no intangible assets held in 2017.

Unsuccessful exploration expenditure relates to costs associated with licence relinquishments and uncommercial well evaluations.

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14. Property, plant and equipmentGroup In millions of $

Oil and gas properties

Other fixed assets Total

COST AT 1 JANUARY 2018 – –

Business combinations 4,339.0 33.9 4,372.9

Additions 435.8 1.9 437.7

Transfers from exploration and evaluation 3.9 – 3.9

Currency translation adjustments (258.5) (2.4) (260.9)

COST AT 31 DECEMBER 2018 4,520.2 33.4 4,553.6

ACCUMULATED DEPRECIATION AT 1 JANUARY 2018

Charge for year (646.5) (2.5) (649.0)

Currency translation adjustments 17.6 – 17.6

ACCUMULATED DEPRECIATION AT 31 DECEMBER 2018 (628.9) (2.5) (631.4)

NET BOOK VALUE AT 31 DECEMBER 2018 3,891.3 30.9 3,922.2

Other fixed assets held in 2017 by the Company amounted to a cost of $40,939 and depreciation of $3,187.

15. Investments Group In millions of $ Equity Loans Total

COST AT 1 JANUARY 2018 – – –

Joint ventures 540.9 – 540.9

AT 31 DECEMBER 2018 540.9 – 540.9

Interest in joint venturesThe analysis of joint ventures during 2018 is analysed as: GroupIn millions of $ 2018

COST AT 1 JANUARY 2018 –

Business combinations 523.1

Share of results in the year 4.0

Equity injection contribution 14.6

Currency translation adjustments (0.8)

AT 31 DECEMBER 2018 540.9

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The Group has a 54 per cent interest in GDF SUEZ E&P Touat BV, which has an interest in the Touat production sharing contract in Algeria. The Group’s interest in Touat is accounted for using the equity method in the consolidated financial statements. Summarised financial information of the joint venture, based on its IFRS financial statements, and reconciliation with the carrying amount of the investment in the consolidated financial statements are set out below:

The summarised statement of financial position of Touat BV is as below: GroupIn millions of $ 2018 2017

Non-current assets 1,045.6

Current assets 82.4 –

Current liabilities (129.8) –

Non-current liabilities (51.0) –

EQUITY 947.2 –

Groups share of equity – 54% (2017: 0%) 511.5 –

GROUPS CARRYING AMOUNT OF THE INVESTMENT 511.5 –

GroupIn millions of $ 2018 2017

General and administration expenses (2.3) –

Finance income 2.4

PROFIT BEFORE TAX 0.1 –

Income tax credit 2.0 –

PROFIT FOR THE YEAR 2.1 –

The contingent liability associated with the Touat development project is disclosed in note 25.

The investment held in the Company during the year is its direct interest in Neptune Energy Group Holdings Limited. Company In millions of $ Equity Loans Total

COST AS AT 1 JANUARY 2018 – – –

Investment in subsidiaries 1,977.2 – 1,977.2

AT 31 DECEMBER 2018 1,977.2 – 1,977.2

16. InventoriesGroup In millions of $

31 December2018

31 December2017

Hydrocarbons – stock of gas 5.1 –

Raw materials and consumables 59.2 –

TOTAL 64.3 –

The Company held no inventories in 2018 or 2017.

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17. Trade and other receivables GroupIn millions of $

31 December 2018

31 December 2017

Amounts falling due within one year:

Trade receivables 358.3 –

Under-lift position 70.6 –

Other receivables 210.7 0.3

Prepayments and accrued income 3.0 0.1

TOTAL 642.6 0.4

Trade receivables are stated net of credit loss provisions of $22 million. When management considers the recovery of a receivable to be improbable, a provision is made against the carrying value of the receivable. CompanyIn millions of $

31 December 2018

31 December 2017

Amounts falling due within one year:

Amounts owed by Group undertakings:

– inter-company loan receivable – 3.1

Other current assets 0.2 –

Amounts falling due after one year:

– inter-company loan receivable 654.0 –

TOTAL 654.2 3.1

In 2017, amounts receivable from Group undertakings as an inter-company loan are unsecured, carry interest of 5 per cent and were repaid when the EPI acquisition was completed on 15 February 2018. The inter-company interest receivable was settled when the EPI acquisition was completed on 15 February 2018.

18. Cash and cash equivalents Group In millions of $

31 December2018

31 December2017

Cash at bank and in hand 191.1 0.4

Restricted cash 6.2 –

TOTAL CASH AND CASH EQUIVALENTS 197.3 0.4

Cash and cash equivalents comprise cash in hand, deposits with maturity of three months or less and other short-term money market deposit accounts that are readily convertible into known amounts of cash. Restricted cash includes monies held for decommissioning obligations.

The Company held $1.1 million cash and cash equivalents at 31 December 2018.

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19. Borrowings Group In millions of $ Interest rate % Maturity

31 December2018

31 December2017

Inter-company loan – 2018 – 3.1

NON-CURRENT INTEREST BEARING LOANS AND BORROWINGS – MORE THAN FIVE YEARS

Reserve base lending facility 5.730 2024 943.4 –

Touat project finance facility 6.000 2024 200.2 –

Subordinated Neptune Energy Group Limited loan 7.750 2024 106.9 –

Senior Notes 6.625 2025 537.7 –

TOTAL 1,788.2 3.1

TOTAL CURRENT – 3.1

TOTAL NON-CURRENT 1,788.2 –

On 11 May 2017, certain subsidiaries within the Group entered into a revolving reserves-based lending facility (RBL) with total aggregate commitments of $2,000 million. The outstanding debt is repayable in line with the amortisation of bank commitments over the period from 1 April 2020 to the final maturity date of 11 May 2024, or such time as is determined by reference to the remaining reserves of the assets, whichever is earlier. The maximum amount that the relevant subsidiaries (the RBL group) can drawdown under this facility is subject to a consolidated cash flow and debt service projection, which is reviewed twice a year, in March and September. On these dates there is a redetermination of the available size of the facility, which takes into account, among other things, the most up-to-date forecast of the RBL group’s production. Until 31 March 2018, the available size of the facility was $1,428 million and from that date and until 30 September 2018, the size was increased to $1,795 million. From 1 October 2018 the size was reduced to $1,725 million and has since been increased to $1,981 million on accession of VNG Norge AS to the RBL facility. The facility is a multi-currency facility and incurs interest on outstanding debt at US dollar and Sterling LIBOR, EURIBOR or NIBOR plus an applicable margin. The facility is secured over the shares of certain companies within the RBL group, and certain of their oil and gas assets. As at 31 December 2018, total drawings under the facility were $1,000 million.

In May 2018, the Company’s 100 per cent subsidiary Neptune Energy BondCo Plc issued $550 million in senior notes due in 2025, bearing interest at an annual rate of 6.625 per cent.

On 27 December 2017, Neptune Energy Touat Holding BV (an indirect 100 per cent subsidiary of the Company) entered into a term loan from ENGIE CC SCRL. The lender has agreed to provide loan financing to fund costs in respect of the Group’s interest in the Touat field in Algeria. As at 31 December 2018, $200.2 million had been drawn under the facility. The loan incurs interest at 6 per cent until production commences at the field and at 8 per cent thereafter.

In February 2018, the Company entered into a $100 million shareholder loan from Neptune Energy Group Limited, for the purposes of part-funding the costs of acquiring the shares in EPI (2017:$nil). The loan is for a period of six years and incurs interest at 7.75 per cent.

20. Financial assets and liabilitiesFinancial risk management objectivesThe Group’s activities expose it to a variety of financial risks including market risk (commodity price risk, foreign currency risk, interest rate risk) credit risk and liquidity risk. The Group’s overall risk management programme focuses on the unpredictability of financial markets and seeks to minimise potential adverse effects on the Group’s financial performance. The Group holds a portfolio of commodity, interest rate and foreign currency derivative contracts, with various counterparties. The use of derivative financial instruments is governed by the Group’s policy approved by the Board of Directors and exposure limits are reviewed internally on a regular basis. The Group does not enter into or trade financial instruments, including derivatives, for speculative purposes.

Fair values of financial assets and liabilitiesWith the exception of hedging derivatives, the Group considers the carrying value of all of its financial assets and liabilities to be materially the same as their fair value. Derivatives and contingent consideration are measured at fair value through profit and loss, while equity instruments are designated as fair value through other comprehensive income. All other financial assets and liabilities are measured at amortised cost.

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Fair values of derivative instrumentsAll fair values are recognised at fair value on the balance sheet with changes in valuation recognised immediately in the income statement, unless the derivatives have been designated as a cash flow hedge. Fair value is the amount for which the asset or liability could be exchanged in an arm’s length transaction at the relevant date. Fair values, where available, are determined using quoted prices in active markets. To the extent that market prices are not available, fair values are estimated by reference to market-based transactions, or using standard valuation techniques for the applicable instruments and commodities involved.

Set out below is an overview of financial assets, other than cash and short-term deposits, held by the Group as at 31 December 2018 including their maturity. For items held at amortised cost there is no significant difference between their fair value and amortised cost value.


31 December 2018

Less than one year

Between two and

five yearsMore than five years Total

FINANCIAL ASSETS AT FAIR VALUE – – – –

Commodity derivatives at fair value through profit and loss 2.0 1.4 – 3.4

Commodity derivatives in qualifying hedging relationships1 31.2 38.7 – 69.9

EQUITY INSTRUMENTS DESIGNATED AT FAIR VALUE THROUGH OCI

10.58% interest in Erdgas-Verkaufs-Gesellschaft mbH, Münster – – 19.7 19.7

FINANCIAL ASSETS AT AMORTISED COST

Trade and other receivables 642.6 – – 642.6

Tax receivable 83.7 – – 83.7

Other non-current assets 8.8 8.8

TOTAL 759.5 40.1 28.5 828.1

1) Of the $31.2 million due under one year, $17.1 million is due within six months.


31 December 2018

Less than one year

Between two and


FINANCIAL ASSETS AT AMORTISED COST

Inter-company loan receivable – – 642.3 642.3

Inter-company interest receivable – – 11.7 11.7

Other current assets 0.2 – – 0.2

TOTAL 0.2 – 654.0 654.2

In 2017, the Company held $3.1 million inter-company loan receivables due within one year at amortised cost.

There are no significant sources of hedge ineffectiveness other than for off-market hedging relationships for hedging instruments acquired from ENGIE on 15 February 2018 as well as for credit risk being included on the hedging instrument and not the hedged item in accordance with IFRS 9.

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Set out below is an overview of financial liabilities, other than cash and short term deposits, held by the Group as at 31 December 2018 including their maturity. The Senior Notes held by the Group have a fair value of $514.3 million, compared with the carrying amount of $537.7 million. This financial liability would be classed as Level 1. For all other items held at amortised cost there is no significant difference between their fair value and amortised cost value.


As at 31 December 2018

Less than one year

Between two and


FINANCIAL LIABILITIES AT FAIR VALUE

Commodity derivatives at fair value through profit and loss 9.9 4.2 – 14.1

Commodity derivatives in qualifying hedging relationships1 51.1 25.2 – 76.3

Interest rate derivatives in qualifying hedging relationships 0.4 1.7 – 2.1

Foreign forward exchange contracts at fair value through profit and loss 12.2 – – 12.2

Contingent consideration of the VNG Norge AS acquisition 24.3 – – 24.3

FINANCIAL LIABILITIES AT AMORTISED COST

LONG TERM BORROWINGS

Reserve base lending facility – – 943.4 943.4

Senior Notes – – 537.7 537.7

Touat project finance facility – – 200.2 200.2

Subordinated Neptune Energy Group Limited loan – – 106.9 106.9

Trade and other payables 94.5 – – 94.5

Wages and social security 51.8 – – 51.8

Corporate taxes payable 188.1 35.7 – 223.8

Other taxes payable 81.0 – – 81.0

Other liabilities 309.2 – 59.6 368.8

TOTAL 822.5 66.8 1,847.8 2,737.1

1) Of the $51.1 million, $28.0 million is due within six months.

In 2017, the Group held $3.1 million short-term borrowings due within one year and a further $1.5 million of trade and other payables due within one year.


As at 31 December 2018

Less than one year

Between two and


FINANCIAL LIABILITIES AT AMORTISED COST

Inter-company loan – – 643.1 643.1

Inter-company interest payable – – 11.6 11.6

TOTAL – – 654.7 654.7

In 2017, the Company held $3.1 million inter-company loan due within one year.

20.1 FAIR VALUE MEASUREMENTSValuationAll financial instruments that are initially recognised and subsequently remeasured at fair value have been classified in accordance with the hierarchy described in IFRS 13 Fair Value Measurement.

Fair value measurement hierarchy The fair value hierarchy, described below, reflects the significance of the inputs used to determine the valuation of financial assets and liabilities measured at fair value.

Level 1 fair value measurements are those derived directly from quoted prices (unadjusted) in active markets for identical assets and liabilities.

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Level 2 fair value measurements are those including inputs other than quoted prices included within Level 1 that are observable for the asset or liability directly or indirectly. The fair value of the Group’s interest rate and currency exchange rate derivatives and the majority of the Group’s commodity derivatives are calculated from relevant market prices and yield curves at the balance sheet date and are therefore based solely on observable price information. These instruments are not directly quoted in active markets and are accordingly classified as Level 2 in the fair value hierarchy.

Level 3 fair value measurements are those derived from valuation techniques that include significant inputs for the asset or liability that are not based on observable market data. Where observable market valuations of commodity contracts are unavailable, the fair value on initial recognition is the transaction price and is subsequently determined using the Group’s forward planning assumptions for the price of gas, other commodities and indices.

Equity investments are valued using the market approach based on a multiple of EBITDA consistent with the valuation obtained for transactions involving investments similar in nature.

All of the Group’s derivatives are Level 2 and 3. There were no financial derivatives held by the Group in 2017 or by the Company in 2017 and 2018.

The following table provides the fair value measurement hierarchy of the Group’s assets:

GroupIn millions of $ Date of valuation

31 December 2018

Total

Significant unobservable

inputs(Level 2)

Significant observable

inputs(Level 3)

ASSETS MEASURED AT FAIR VALUE

DERIVATIVE FINANCIAL ASSETS

Commodity derivatives in qualifying hedging relationships 31 December 2018 69.9 69.9 –

Commodity derivatives at fair value through profit and loss 31 December 2018 3.4 3.4 –

NON-LISTED EQUITY INSTRUMENTS

10.58% interest in Erdgas Münster GMBH 31 December 2018 19.7 – 19.7

TOTAL 93.0 73.3 19.7

The valuation of Neptune’s interest in Erdgas Münster has been calculated based on an enterprise value/EBITDA multiple taking into account recent transactions involving suitable comparative infrastructure companies and was acquired as a consequence of the EPI acquisition. For 2017 year end the assets measured at fair value was nil.

The following table provides the fair value measurement hierarchy of the Group’s liabilities:

GroupIn millions of $ Date of valuation

31 December 2018

Total

Significant observable

inputs(Level 2)

Significant unobservable

inputs(Level 3)

LIABILITIES MEASURED AT FAIR VALUE

DERIVATIVE FINANCIAL LIABILITIES

Commodity derivatives in qualifying hedging relationships 31 December 2018 76.3 76.3 –

Commodity derivatives at fair value through profit and loss 31 December 2018 14.1 14.1 –

Interest rate derivatives in qualifying hedging relationships 31 December 2018 2.1 2.1 –

Forward foreign exchange contracts at fair value through profit and loss 31 December 2018 12.2 12.2 –

TOTAL 104.7 104.7 –

There were no transfers between fair value levels in the year for either assets or liabilities. For 2017 year end the liabilities measured at fair value was nil.

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20.2 LEVEL 3 FAIR VALUE MOVEMENTSThe movements in the year associated with the non-listed equity investments classified as equity instruments designated at fair value through OCI in accordance with Level 3 are shown below:

In millions of $

Group Company

31 December2018

31 December2017

31 December2018

31 December2017

FAIR VALUE AT 1 JANUARY – – – –

Acquisitions 21.2 – – –

Currency translation adjustments (1.5) – – –

FAIR VALUE AT 31 DECEMBER 19.7 – – –

A 5 per cent change in the EBITDA multiple to the Level 3 instrument above as applied would result in a $1 million change in valuation.

The movements in the year associated with the non-listed equity investments classified as equity instruments designated at fair value through profit and loss in accordance with Level 3 are shown below:

In millions of $

Group Company

31 December2018

31 December2017

31 December2018

31 December2017

FAIR VALUE AT 1 JANUARY – – – –

Acquisitions 3.1 – – –

Total gains or losses recognised in the income statement 1.2 – – –

Disposals (4.3) – – –

Currency translation adjustments – – – –

FAIR VALUE AT 31 DECEMBER – – – –

On 18 December 2018, the Group sold its equity investment in General Energy Recovery Inc, a Canadian company engaged in R&D for a net profit of $1.2 million.

20.3 HEDGING RESERVEThe hedge reserve represents the portion of deferred gains and losses on hedging instruments deemed to be effective cash flow hedges. The movement in the reserve for the period is recognised in other comprehensive income. The following table summarises the hedge reserve by type of derivative, net of tax effects.


Cash flowcommodity

hedge reserve

Cost of commodity

hedging reserve

Cash flow interest rate

hedge reserve

Cost of interest rate

hedging reserve

Total hedge reserve

AT 1 JANUARY 2018 – – – –

Add: costs of hedging deferred and recognised in OCI 179.9 9.7 2.2 (0.4) 191.4

Less: reclassified from OCI to profit or loss or included in finance costs (161.2) (1.2) (1.0) 0.4 (163.0)

Less: deferred tax (1.7) (1.6) – – (3.3)

AT 31 DECEMBER 2018 17.0 6.9 1.2 – 25.1

Excluded from the table above is $2.4 million of hedge ineffectiveness that was taken directly into the profit and loss. The value of any CVA adjustment is not material.

There were no financial derivatives held by the Group in 2017 or by the Company in 2017 and 2018.

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21. Financial risk factorsThe Group did not enter into any enforceable master netting arrangements.

The Group’s senior management oversees the management of financial risk. The Group’s senior management ensures that financial risk-taking activities are governed by appropriate policies and procedures and that financial risks are identified, measured and managed in accordance with Group policies and risk objectives, All derivative activities for risk management purposes are carried out by specialist teams, both internal and external, that have the appropriate skills, experience and supervision.

Market risk is the risk that the fair value of future cash flows of a financial instrument will fluctuate because of changes in market prices. Market risk comprises three types of risk: commodity price risk, interest rate risk and foreign currency risk. Financial instruments mainly affected by market risk include loans and borrowings, deposits and derivative financial instruments.

The sensitivity analyses in the following sections relate to the position as at 31 December 2018 (2017 nil as there was limited trading activity).

The sensitivity analyses have been prepared on the basis that the amount of financial instruments are all constant. The sensitivity analyses are intended to illustrate the sensitivity to changes in market variables on the composition of the Group’s financial instruments at the balance sheet date and show the impact on profit or loss and shareholders’ equity, where applicable.

The following assumptions have been made in calculating the sensitivity analyses:

• the sensitivity of the relevant profit before tax item and/or equity is the effect of the assumed changes in respective market risks for the full year based on the financial assets and financial liabilities held at the balance sheet date;

• the sensitivities indicate the effect of a reasonable increase in each market variable. Unless otherwise stated, the effect of a corresponding decrease in these variables is considered approximately equal and opposite; and

• fair value changes from derivative instruments designated as cash flow hedges are considered fully effective and recorded in shareholders’ equity, net of tax.

Fair value changes from derivatives and other financial instruments not designated as cash flow hedges are presented as a sensitivity to profit before tax only and not included in shareholders’ equity.

21.1 LIQUIDITY RISKLiquidity risk is the risk that the Group might not have sources of funding to meet its business needs. The Group manages its liquidity risk using both short and long-term cash flow projections, supplemented by debt financing and an active portfolio management. The Board of Directors who have ultimate responsibility for liquidity risk management believe that the Group has sufficient cash, undrawn committed funds under its borrowing base facility and expected sources of liquidity to meet the business’s forecast requirements for the short, medium and long term.

The Group assessed the concentration of risk with respect to refinancing its debt and concluded it to be low. The Group has access to a sufficient variety of sources of funding and debt maturing within 12 months can be rolled over with existing lenders.

21.2 CREDIT RATE RISKCredit risk is managed on a Group basis. Currently credit risk only arises from cash and cash equivalents, sales receivables and hedging derivatives. For banks and financial institutions, only independently rated parties with a minimum rating of ‘BBB’ are accepted. The Group does not have any significant credit risk exposure to any single counterparty or any group of counterparties.

The Group’s maximum exposure to credit risk for the components of the statement of financial position at 31 December 2018 and 2017 is the carrying amounts as illustrated in note 20.

21.3 MARKET RISKFinancial instruments used by the Group that are affected by market risks primarily comprise cash and cash equivalents, borrowings and derivative contracts. Due to the nature of its operations, the Group carries a natural exposure to gas and oil prices, generating commodity-market-related volatility on its earnings.

The Group identifies, governs and manages this market price exposure through a dedicated market risks policy.

One of the elements of the Group market risks policy is to implement a hedging programme on forecasted sales of produced gas and oil products. The hedging programme aims at smoothening the impact of gas and oil price volatility on earnings by reducing exposure to market prices. It thereby improves earnings predictability of the Group.

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The Group’s hedging programme is focused on reducing volatility of the net earnings, taking into account the underlying pricing structure of sales contracts, production uncertainties and fiscal impacts of hedging.

This hedging programme applies to price exposures of the major affiliates of the Group: Neptune Energy Norge AS, Neptune Energy Nederland B.V., Neptune Energy E&P Holdings Netherlands B.V., Neptune Energy Deutschland GmbH, and Neptune E&P UK Ltd.

The Group holds the following commodity forward contracts:

Group VolumesAverage

pricePeriod

of hedge

OIL HEDGES VS BRENT mmbbl $/bbl

Commodity cap 6.0 75.2 up to 3 years

Commodity floor 5.5 58.7 up to 3 years

Commodity swap 0.7 51.3 up to 3 years

GAS HEDGES VS NBP mmbtu $/mmbtu

Commodity cap 37,141 7.84 up to 3 years

Commodity floor 37,141 5.93 up to 3 years

Commodity swap 17,746 5.26 up to 3 years

GAS HEDGES VS TTF mmbtu $/mmbtu

Commodity cap 35,926 7.87 up to 3 years

Commodity floor 35,926 5.82 up to 3 years

Commodity swap 8,674 5.25 up to 3 years


Aggregate post-tax hedge ratioNeptune’s hedge ratio for commodity derivatives is calculated after applying a 10 per cent headroom against entitlement forecast production and is designed to protect post-tax revenues.

2019 2020 2021

Oil 47% 21% 0%

Gas 56% 40% 13%

Oil price hedges include hedges of realisations for gas production sold as LNG and priced in relation to oil prices.

Post-tax hedge ratios adjust for different tax rates on physical sales and hedge gains and losses, which mean that effective post-tax hedges can be achieved through hedging contracts for volumes, which may be significantly less than anticipated sales.

Sensitivities of the commodity-related financial derivatives portfolio used as part of the portfolio management activities at 31 December, are detailed in the table below and are reasonably foreseeable market movements to the Group’s financial instruments. They are not representative of future changes in consolidated earnings and equity, in so far as they do not include the sensitivities relating to the purchase and sale contracts for the underlying commodities.

In millions of $

31 December 2018

Pricemovement

Pre-tax impact on

income

Pre-tax impact on

equity

SENSITIVITY ANALYSIS

NBP gas price +10% pence/therm increase

(6.5) 45.6

NBP gas price -10% pence/therm decrease

5.9 (44.9)

Brent oil price +10%/bblincrease

(0.1) 23.9

Brent oil price -10%/bbldecrease

(0.6) (25.2)

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21.4 FOREIGN CURRENCY RISKThe Group conducts and manages its business predominantly in US dollars, the operating currency of the oil and gas industry. However, as the Group operates internationally it is therefore exposed to foreign exchange risk arising from various currency exposures, primarily with respect to the Euro and Norwegian Krone (NOK). Foreign exchange risk arises from future commercial transactions, recognised assets and liabilities and net investments in foreign operations.

The Group is exposed to currency risk, defined as the impact on its statement of financial position and income statement of fluctuations in exchange rates effecting its operating and financing activities. Currency risk comprises (i) transaction risk arising in the ordinary course of business, (ii) specific transaction risks related to investments, mergers-acquisitions projects and (iii) the risk arising on the consolidation in USD of subsidiary financial statements with a functional currency other than the USD.

The Group is holding the following cross currency derivative contracts:

Group Currency Terms

$/EURO FORWARD $200 million 1 month USD Libor

vs 1 monthEuribor

Within 3 months


The table below illustrates the indicative pre-tax effects on the income statement and other comprehensive income of applying reasonably foreseeable market movements to the Group’s financial instruments at the balance sheet date.


Pre-tax impact on

income

Pre-tax impact on

equity

SENSITIVITY ANALYSIS

+10% Euro (22.8) –

-10% Euro 21.3 –

+10% NOK (19.8) –

-10% NOK 24.1 –

There were no currency derivatives held at or during 2017.

21.5 INTEREST RATE RISK The Group is exposed to the impact of interest rate fluctuations on its consolidated statements. The Group monitors its exposure to fluctuations in interest rates and may use interest rate derivatives to manage the fixed and floating composition of its borrowings.

The Group is holding the following interest rate derivative contracts:

Group Currency TermsPeriod

of hedge

INTEREST RATE SWAPS $400 million Average 2.59%

Up to 3 years


During 2018, the Group has entered into interest rate derivatives to manage its exposure to fluctuations in the $ interest rate. The impact on 2018 reported income and on equity of a 100 basis point movement in the $ year-end interest rate would be as follows:


31 December 2018

Pre-tax impact on

income

Pre-tax impact on

equity

+100 basis points (0.1) (8.7)

-100 basis points (0.0) 8.9

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22. Trade payables and other liabilities Group In millions of $

31 December2018

31 December2017

Trade and other payables 94.5 1.5

Other current liabilities 333.5 –

Wages and social security 51.8 –

Other tax payables 81.0 –

CURRENT TRADE PAYABLES AND ACCRUALS 560.8 1.5

Other non-current liabilities 59.6 –

NON-CURRENT TRADE PAYABLES AND ACCRUALS 59.6 –

TOTAL 620.4 1.5

Trade payables are usually paid within 30 days of recognition. The carrying amount of financial liabilities approximates their fair value and they are all due within one year. CompanyIn millions of $

31 December2018

31 December2017

Inter-company interest payable > 1 year 11.6 –

Inter-company loan payable > 1 year 643.1

Inter-company loan payable < 1 year – 3.1

TOTAL 654.7 3.1

The Company 2017 inter-company interest payable was settled when the EPI acquisition was completed on 15 February 2018.

23. ProvisionsGroupIn millions of $ Decommissioning Restructuring

Post-employment

benefits Other Total

AT 1 JANUARY 2018 – – – – –

Business combinations 1,545.7 11.5 250.8 18.8 1,826.8

Charge for the year 16.5 (2.8) 13.9 (17.3) 10.3

Unwinding of discount 30.9 – 3.6 – 34.5

Additions 73.6 – – – 73.6

Currency translation and other adjustments (116.8) – (14.5) – (131.3)

Utilisation/paid (29.2) (3.0) (21.3) – (53.5)

Unused provisions released to income statement (15.9) – – – (15.9)

AT 31 DECEMBER 2018 1,504.8 5.7 232.5 1.5 1,744.5

The restructuring provision relates to the transformation activity of the business. There were no provisions for the Group in 2017 or the Company in both 2018 and 2017.


31 December2018

31 December2017

CURRENT

Restructuring 5.7 –

Decommissioning 62.1 –

Other 1.5 –

CURRENT TOTAL 69.3 –

NON-CURRENT

Post-employment benefit and other long term benefits 232.5 –

Decommissioning 1,442.7 –

NON-CURRENT TOTAL 1,675.2

TOTAL 1,744.5 –

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The Group makes full provision for the future cost of decommissioning oil production facilities and pipelines on a discounted basis on the installation of those facilities. The decommissioning provision represents the present value of decommissioning costs relating to oil and gas properties, which are expected to be incurred up to the end of the operations. These provisions have been created based on the Group internal estimates.

Assumptions, based on the current economic environment, have been made which management believe are a reasonable basis upon which to estimate the future liability. These estimates are reviewed regularly to take into account any material changes to the assumptions. However, actual decommissioning costs will ultimately depend upon future market prices for the necessary decommissioning works required which will reflect market conditions at the relevant time.

Furthermore, the timing of decommissioning is likely to depend on when the fields cease to produce at economically viable rates. This in turn will depend upon future oil and gas prices, which are inherently uncertain.

This provision is matched with an entry to property, plant and equipment. The depreciation charge on this asset is included within current operating income and the cost of unwinding of discount is booked in financial expenses.

24. Called up share capital

Group and Company Number $million

ALLOTTED, CALLED UP AND FULLY PAID

Issued in the period 728 0.0

AT 31 DECEMBER 2017 728 0.0

Issued in the period 1,977,174,473 1,977.2

AT 31 DECEMBER 2018 1,977,175,201 1,977.2

On incorporation on 22 March 2017, 728 $1 shares were allotted, called up and fully paid.

On 15 February 2018, a further 1,977,174,473 $1 shares were allotted, called up and fully paid.

25. Commitment and contingencies25.1 OPERATING LEASE COMMITMENTSThe Group has financial commitments in respect of operating leases. The future minimum rentals payable under non-cancellable operating leases are as follows:

In millions of $

Group Company

31 December2018

31 December2017

31 December2018

31 December2017

AMOUNTS DUE

Within one year 32.2 – – –

After one year but within two years 42.4 – – –

After two years but not more than five years 81.7 – – –

More than five years 32.5 – – –

TOTAL 188.8 – – –

Operating lease payments represent rentals payable by the Group for certain of its office properties and for the Group’s net share of supply vessels and support transportation for operational fields.

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25.2 CAPITAL COMMITMENTS Group Company


201831 December

201731 December

201831 December

2017

AMOUNTS DUE

Within one year 352.6 – – –

After one year but within two years 93.4 – – –

TOTAL 446.0 – – –

As at 31 December 2018, the Group had commitments for future capital expenditure amounting to $446.0 million (2017: $nil). Where the commitment relates to a joint arrangement, the amount represents the Group’s net share of the commitment. Where the Group is not the operator of the joint arrangement, then the amounts are based on the Group’s net share of committed future work programmes.

25.3 CONTINGENCIESAs at 31 December 2018, the Group had contingent liabilities of $15 million as described below. As at 31 December 2017, the Group had contingent liabilities relating to financing the transaction costs associated with the acquisition of EPI. The Company had no contingencies in either period.

25.4 LEGAL PROCEEDINGS During the normal course of its business, the Group may be involved in disputes, including tax disputes. The Group has made accruals for probable liabilities related to litigation and claims based on management’s best judgement and in line with IAS 37 and IAS 12.

The Group has not identified any material contingent liabilities other than the disputes discussed below.

Development project CCC (Consolidated Contractors Group) and DAH (Dar El Handasah) have issued a claim to Groupement Touat Gaz (GTG) under the EPC contract for the construction of the living quarters. The claim consists of an extension of time and additional costs. The claim lacks substantiation and legal justification and GTG has rejected the claim. Parties are in discussions to agree on a path forward. The joint venture between ENGIE and Neptune (GDF SUEZ E&P Touat BV) holds 65 per cent in GTG. Neptune Energy holds a 54 per cent share in the joint venture with ENGIE.

There are no pending legal proceedings for the Company as at 31 December 2018 (2017: none).

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26. Related party transactionsThe note describes the material transactions between the Group and its related parties.

The Group’s main subsidiaries are listed in note 28.

GROUP

Related party undertakingPrincipal activities

Country of incorporation

% Equity Interest

Neptune Energy Group Holdings Limited Management and technical

services

United Kingdom

100

The ultimate holding parent is Neptune Energy Group Limited, which is based in London, United Kingdom. During the year, the Group entered into the following transactions in the ordinary course of business on an arm’s length basis, with related parties:

Related party undertaking $ Nature of transactions PurchasesAccounts

payable

Neptune Oil and Gas Limited Management services 0.5 –

William Samuel Hugh Laidlaw is a director of Neptune Oil and Gas Limited. Neptune Oil and Gas Limited provides management services and other administrative costs, including the services of Mr. Laidlaw, certain office costs and expenses.

Transactions with Group investors:

Related party undertaking $ Nature of transactions PurchasesAccounts

payable

CIEP Neptune S.A.R.L (Carlyle investor) Advisory services 10.2 –

Oceanus Jersey Limited (CVC investor) Advisory services 1.0 –

Beijing Rheingau Investment Corporation (CIC investor) Advisory services 12.5 –

Terms and conditions of transactions with related partiesThe finance income and expenses from related parties are made on terms equivalent to those that prevail in arm’s length transactions. Outstanding balances at the year end are unsecured. There have been no guarantees provided or received from any related party receivables or payables. For the period ended 31 December 2018, the Group has not recorded any impairment of receivables relating to the amounts owned by related parties. This assessment is undertaken throughout the financial year through examining the financial position of the related party and the market in which the related party operates.

Compensation of key management personnel of the GroupKey management includes the Directors of the Company and its subsidiaries. The compensation paid or payable to key management for employee services is shown below:

In $ millions 2018 2017


TOTAL COMPENSATION PAID TO KEY MANAGEMENT PERSONNEL 17.6 0.4

There are no other related party transactions.

COMPANYThere are no related party transactions other than inter-company interest and loans.

Terms and conditions of transactions with related partiesThe finance income and costs from related parties are made on terms equivalent to those that prevail in arm’s length transactions. Outstanding balances at the year end are unsecured. There has been no guarantees provided or received from any related party receivables or payables. For the period ended 31 December 2018, the Company has not recorded any impairment of receivables relating to the amounts owned by related parties. This assessment is undertaken throughout the financial year through examining the financial position of the related party and the market in which the related party operates.

Compensation of key management personnel of the CompanyThere is no compensation for key management/Directors included in Neptune Energy Group Midco Limited. There were no other related party transactions.

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27. Pension and post-retirement benefits27.1 DESCRIPTION OF THE MAIN PENSION PLANSPension commitments are measured on the basis of actuarial assumptions. These include assumptions in respect of mortality rates and future salary increases, as well as appropriate discount rates. The Group considers that the assumptions used to measure its obligations are appropriate and documented. However, any changes in these assumptions may have a material impact on the resulting calculations.

The Group provides pension benefits to its employees that are in line with common market practice in the countries where Neptune operates. These consist of both defined contribution and defined benefit arrangements. The latter are either career average or final salary based on employee pensionable earnings and length of service. The plan in the UK is defined contribution.

The Group also provides other post-employment benefits and these are mainly end of service gratuities and energy price subsidies, commonly provided by the industry in France.

NetherlandsNeptune Energy Nederland BV and its Dutch subsidiaries have a defined benefit pension plan covering substantially all of its employees, which requires contributions to be made to a fund administered by ASR. Plan assets are assets that are held by a long-term employee benefit fund or qualifying insurance policies. Assets held by a long-term employee benefit fund are assets (other than non-transferable financial instruments issued by the reporting entity) that are held by an entity (a fund) that is legally separate from the reporting entity and exists solely to pay or fund employee benefits and are available to be used only to pay or fund employee benefits, are not available to the reporting entity’s own creditors (even in bankruptcy), and cannot be returned to the reporting entity.

GermanyNeptune Energy Deutschland have seven defined benefit plans, corresponding to different groups of employees successively incorporated in the Company. The defined benefit plans are financed by book reserves. Five of the plans are closed to new entrants but still occur service costs.

France Since 1 January 2005, the CNIEG (Caisse Nationale des Industries Électriques et Gazières) has operated the pension, disability, death, occupational accident and occupational illness benefit plans for electricity and gas industry companies. The CNIEG is a social security legal entity under private law placed under the joint responsibility of the ministries in charge of social security, budget and energy. Salaried employees and retirees have been fully affiliated to the CNIEG since 1 January 2005. The Group company covered by this plan is Neptune Energy International SA. Pension benefit obligations and other ‘mutualised’ obligations are assessed by the CNIEG.

NorwayNeptune Energy Norge is required to have an occupational pension scheme in accordance with Norwegian law. The defined benefit pension plan is administered by Storebrand AS and contributions are made to book reserves. Accounting for pensions is based on linear vested principles and on expected wages at retirement date. Changes in pension schemes are amortised over the estimated average remaining periods.

27.2 GOVERNANCEThe Group’s externally funded plans are established under trusts, or similar entities such as insurance contracts. The operation of these entities is governed by local regulations and practice in each country as is the relationship between the local country management and the Trustees, or their equivalent, and the composition of these bodies. Where Trustees or their equivalents are in place they generally act on behalf of the plan’s stakeholders. Periodic reviews are carried out on the solvency of the plans in accordance with local legislation and play a role in the long-term investment and funding strategy.

Plans are externally funded except within those countries where it is common practice to use book reserves, for example, in Germany.

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27.3 DEFINED BENEFITS PLANS27.3.1 Change in benefit obligations and plan assets The table below shows the amount of the Group’s projected benefit obligations and plan assets, changes in these items during the periods presented, and their reconciliation with the amounts reported in the statement of financial position:


Pension benefit

obligations1

Other post- employment

benefit obligations2

Long-term benefit

obligations3

Total benefit

obligations

A – CHANGE IN PROJECTED BENEFIT OBLIGATIONS

PROJECTED BENEFIT OBLIGATIONS AT 1 JANUARY 2018

Business combination (406.6) (40.4) (7.2) (454.2)

Service cost (10.5) (2.9) (0.5) (13.9)

Interest cost on benefit obligations (6.9) (0.5) (0.1) (7.5)

Financial actuarial gains and losses (11.7) 0.1 0.1 (11.5)

Demographic actuarial gains and losses 11.5 14.5 2.6 28.6

Benefits paid 12.6 5.2 0.3 18.1

Other (translation adjustments) (4.9) – – (4.9)

PROJECTED BENEFIT OBLIGATION AT 31 DECEMBER A (416.5) (24.0) (4.8) (445.3)

The business combination projected benefit obligation relates to the acquisition of the ENGIE business, on the acquisition of VNG, Neptune did not acquire any defined benefit obligations.


Pension benefit

obligations1



Long-term benefit

obligations3

Total benefit

obligations

B – CHANGE IN FAIR VALUE OF PLAN ASSETS

FAIR VALUE OF PLAN ASSETS AT 1 JANUARY 2018

Business combination 199.3 – – 199.3

Interest income on plan assets 4.1 – – 4.1

Financial actuarial gain and losses 6.1 – – 6.1

Contributions received 14.8 4.7 – 19.5

Benefits paid (11.5) (4.7) – (16.2)

Other (translation adjustments) – – – –

FAIR VALUE OF PLAN ASSETS AT 31 DECEMBER B 212.8 – – 212.8


C – FUNDED STATUS A+B

NET BENEFIT OBLIGATION (203.7) (24.0) (4.8) (232.5)

As at 31 December 2018 the pre-paid benefit cost was $nil. There were no defined benefit obligations within the Group in 2017.

1) Pensions and retirement bonuses

2) Gratuities and other post-employment benefits

3) Length of service awards and other long-term benefits

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27.4 COMPONENTS OF NET PENSION COST


31 December2018

31 December2017

Current service cost 13.8 –

Net interest expense 3.3 –

Actuarial gains and losses on long term benefit obligations (2.6) –

Non-recurring items 1.5 –

TOTAL 16.0 –

RECORDED IN OCI 3.7 –

RECORDED IN NET FINANCE COSTS 12.3 –

27.5 FUNDINGThe funding of these obligations at 31 December 2018 can be analysed as follows:


Projected benefit

obligation Fair value of plan assets

Total net obligation

Underfunded plans (229.7) 212.8 (16.9)

Unfunded plans (215.6) – (215.6)

AS AT 31 DECEMBER 2018 (445.3) 212.8 (232.5)

The allocation of plan assets by principal asset category can be analysed as follows:

% of total31 December

201831 December

2017

Equity investments 11 –

Other 89 –

TOTAL 100 –

All of the plan assets are located in the Europe geographical area.

27.6 ACTUARIAL ASSUMPTIONSWith the objective of presenting the assets and liabilities of the pension and other post-employment benefit plans at their fair value on the balance sheet, assumptions under IAS 19 are set by reference to market conditions at the valuation date. The actuarial assumptions used to calculate the benefit liabilities vary according to the country in which the plan is situated.

The discount rate applied is determined based on the yield, at the date of the calculation, on top-rated corporate bonds with maturities mirroring the term of the plan.

Pension benefit

obligations1



Long term benefit

obligations3Total benefit

obligationsGroup

DISCOUNT RATE 1.85% 1.85% 1.85% 1.85%

INFLATION RATE 1.8% 1.8% 1.8% 1.8%

1) Pensions and retirement bonuses

2) Gratuities and other post-employment benefits

3) Length of service awards and other long-term benefits

Discount ratesThe discount rate applied is determined based on the yield, at the date of the calculation, on top-rated corporate bonds with maturities mirroring the term of the plan.

The rates were determined for each monetary area based on data for AA corporate bonds yields. For Eurozone, data (from Bloomberg) are extrapolated on the basis of government bond yields for long maturities.

According to the Group’s estimates, a 100 basis points increase or decrease in the discount rate would result in a change of approximately 16 per cent in the projected benefit obligation.

The inflation rate were determined for each area. A 100 basis points increase or decrease in the inflation rate, with no change on the discount rate, would result in a change of approximately 16 per cent in the projected benefit obligation.

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28. Principal subsidiary undertakings, joint ventures, associatesAt 31 December 2018, the principal subsidiary undertakings of the Company which were wholly owned were:

Country of incorporation Holding

Proportion of voting

rights and shares held

Main activity

Neptune Energy International S.A. France 100% 100% Holding Company

Neptune Energy Bondco Plc UK 100% 100% Financing Company

Neptune Energy Finance Limited UK 100% 100% Financing Company

Neptune Energy Capital Limited UK 100% 100% Financing Company

Neptune Energy Norge AS Norway 100% 100% Oil and gas

Neptune Energy Group Holdings Limited UK 100% 100% Holding Company

Neptune Energy Holding Netherlands BV Netherlands 100% 100% Holding Company

Neptune Energy E&P Holdings Netherlands BV Netherlands 100% 100% Holding Company

Neptune Energy Netherlands BV Netherlands 100% 100% Oil and gas

Neptune Energy Participation Netherlands BV Netherlands 100% 100% Oil and gas

Production North Sea Netherlands Ltd USA 100% 100% Oil and gas

Neptune Energy Egypt BV Netherlands 100% 100% Oil and gas

ENGIE Sud Est Illizi BV Netherlands 100% 100% Oil and gas

Neptune Energy Arguni I BV Netherlands 100% 100% Oil and gas

Neptune Energy Jakarta BV Netherlands 100% 100% Oil and gas

Neptune Energy France SAS France 100% 100% Oil and gas

Neptune E&P UK Ltd UK 100% 100% Oil and gas

Neptune E&P UKCS Ltd UK 100% 100% Oil and gas

Neptune Energy Holding Germany GmbH Germany 100% 100% Holding Company

Neptune Energy Deutschland GmbH Germany 100% 100% Oil and gas

Westdeutsche Erdölleitung GmbH Germany 50% 50% Oil and gas

Gewerkschaft Küchenberg Erdgas und Erdöl Germany 50% 50% Oil and gas

BHKW Manschnow GmbH Germany 50% 50% Oil and gas

Neptune Energy Australia Pty Ltd Australia 100% 100% Oil and gas

Neptune Energy Bonaparte Pty Ltd Australia 100% 100% Oil and gas

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Country of incorporation Holding

Proportion of voting

rights and shares held

Main activity

Neptune Energy Alam El Shawish BV Netherlands 100% 100% Oil and gas

Neptune Energy South West Alamein BV Netherlands 100% 100% Oil and gas

Neptune Energy Muara Bakau BV Netherlands 100% 100% Oil and gas

Neptune Energy North Ganal BV Netherlands 100% 100% Oil and gas

Neptune Energy Denmark Aps Denmark 100% 100% Oil and gas

Neptune Energy Facilities Netherlands BV Netherlands 100% 100% Oil and gas

Neptune Energy Brasil Participacoes Ltda Brazil 100% 100% Oil and gas

Neptune Energy Ashrafi BV Netherlands 100% 100% Oil and gas

Neptune Energy Algeria BV Netherlands 100% 100% Oil and gas

GDF SUEZ E&P Eastern Indonesia BV Netherlands 100% 100% Oil and gas

ENGIE E&P Malaysia BV Netherlands 100% 100% Oil and gas

Neptune Energy Western Exploration BV Netherlands 100% 100% Oil and gas

Neptune Energy East Ganal BV Netherlands 100% 100% Oil and gas

Gaz de France Exploration Libya BV Netherlands 100% 100% Oil and gas

GDF SUEZ Exploration Mauritania BV Netherlands 100% 100% Oil and gas

Neptune Energy East Sepinggan BV Netherlands 100% 100% Oil and gas

Neptune Energy New Projects BV Netherlands 100% 100% Oil and gas

GDF SUEZ E&P Touat BV Netherlands 54% 54% Oil and gas

Neptune Energy Touat Holding BV Netherlands 100% 100% Oil and gas

29. Events after the reporting periodThere were no reportable balance sheet events after the reporting date.

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SUPPLEMENTARY INFORMATIONGAS AND OIL (UNAUDITED)

Reserves⁴The geographical allocation of reserves is as below:

Proved plus probable reserves (mmboe)

Norway Netherlands UK GermanyNorthAfrica

Asia Pacific Total

2P reserves at 31 December 2017 241 46 42 73 86 66 5551

Acquisitions 46 – 13 – – – 59

Revisions, extensions and discoveries 87 3 9 (14) 1 (6) 79

Under/overlift 1 – – – – – 1

Production (27) (10) (6) (5) (2) (8) (57)2

2P RESERVES AT 31 DECEMBER 2018 348 38 58 55 85 53 638

1) Engie numbers as of 31 December 2017. We now report management estimates, which are independently audited by ERC.

2) As per PRMS (SPE/SPEE/WPC/AAPG/SEG) guidance, production is equal to the liftings.

3) Numbers may not add up due to rounding differences.

4) These reserves do not include contingent resources (2C).

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GENERAL INFORMATION

This report includes the results of the acquired EPI business consolidated since 15 February 2018, which is the acquisition date as that is when Neptune acquired control over EPI. Equivalent data for Neptune for the corresponding reporting period ended 31 December 2017, starting when the Company was incorporated on 22 March 2017, are generally not informative, as the Company had minimal activity at the time, principally comprising only minor administration expenses. Therefore, in respect of certain measures, including production, EBITDAX and capital expenditure, we have provided additional approximate pro forma information relating to the acquired EPI business, to enable a comparison of the results for the full year ended 31 December 2018 (including the period prior to our acquisition on 15 February) with those for the full year ended 31 December 2017.

In this report, unless otherwise indicated, our production, reserves and resources figures are presented on a basis including our ownership share of volumes of companies that we account for under the equity accounting method, in particular, for the interest held in the Touat project in Algeria through a joint venture company. Production for interests held under production sharing contracts is reported on an appropriate unit of production basis.

Forward-looking statements The discussion in this report includes forward-looking statements which, although based on assumptions that we consider reasonable, are subject to risks and uncertainties which could cause actual events or conditions to materially differ from those expressed or implied by the forward-looking statements. While these forward-looking statements are based on our internal expectations, estimates, projections, assumptions and beliefs as at the date of such statements or information, including, among other things, assumptions with respect to production, future capital expenditures and cash flow, we caution you that the assumptions used in the preparation of such information may prove to be incorrect and no assurance can be given that our expectations, or the assumptions underlying these expectations, will prove to be correct. Any forward-looking statements that we make in this report speak only as of the date of such statement or the date of this report.

Alternative performance measures This report contains non-GAAP and non-IFRS measures and ratios that are not required by, or presented in accordance with, any generally accepted accounting principles (GAAP) or IFRS. These non-IFRS and non-GAAP measures and ratios may not be comparable to other similarly titled measures of other companies and have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our operating results as reported under IFRS or GAAP. Non-IFRS and non-GAAP measures and ratios are not measurements of our performance or liquidity under IFRS or GAAP and should not be considered as alternatives to operating profit or profit from continuing operations or any other performance measures derived in accordance with IFRS or GAAP or as alternatives to cash flow from operating, investing or financing activities.

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GET IN TOUCH

London +44 20 7832 3900

Oslo +47 51 53 89 00

Paris +33 1 79 36 06 55

Zoetermeer +31 79 368 68 68

Perth +61 8 6160 8440

Contact details for other offices can be found on our website.

Registered office Nova North, 11 Bressenden Place SW1E 5BY London United Kingdom

Neptune Energy Group Midco Limited is a private limited company registered in England and Wales (No. 10684661).

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NEPTUNE ENERGY ANNUAL REPORT AND ACCOUNTS 2018 · Neptune Energy Annual Report and Accounts 2018 An international independent gas and oil exploration and production company, with