NEPTUNE ENERGY 2020 1 st QUARTER RESULTS Neptune Energy Group Midco - - PDF document

NEPTUNE ENERGY 2020 1st QUARTER RESULTS

Neptune Energy Group Midco Limited Unaudited Condensed Consolidated Financial Statements For the three months ended 31 March 2020

Neptune Energy Group Midco Limited Report for the period ended 31 March 2020 2

About Neptune Energy Group

Neptune is an independent global E&P company and active across the North Sea, North Africa and Asia Pacific. The Company’s parent company, Neptune Energy Group Limited, is backed by CIC and funds advised by The Carlyle Group and CVC Capital Partners. Further background information is available on the corporate website www.neptuneenergy.com General 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. In this report, unless otherwise indicated, our production, reserves and resources figures are presented on a basis including our

• wnership 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. 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

• ther 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. 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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NEPTUNE ENERGY ANNOUNCES Q1 2020 RESULTS London, 27 May 2020 – Neptune Energy, the global independent oil and gas exploration and production company, today announces its financial results for the three months ended 31 March 2020. Strong operational performance, with production for the period above full year guidance  Strong operational performance with limited disruption from COVID-19 on operations  Production averaged 162.1 kboepd for the first quarter with high production efficiency; Touat reached plateau in April  Maintaining full year production guidance of 145-160 kboepd  Exploration success with discoveries in Norway, the UK and Germany Robust financial performance, low operating costs and increased liquidity  Robust cash flow of $355 million for the period; resilience plan and hedging mitigate weaker commodity prices  Lower operating costs of $8.9/boe for the period, full year guidance reduced to <$10/boe  Completed redetermination of RBL borrowing base to $2.3 billion and upsizing to $2.6 billion, increasing total available liquidity to $1.7 billion  Agreed to terminate the agreement to acquire Edison E&P’s UK and Norwegian subsidiaries from Energean Oil & Gas  Net debt to EBITDAX of 0.99 times at the end of the period Resilience plan delivering efficiencies, on target for full year cost reductions of $300-400 million  2020 operating cost and G&A cost savings of $50 million identified and being delivered  Project development schedules have been deferred. 2020 capex reductions expected to be in excess of $300 million; full year development capex guidance lowered to $700-800 million. Near-term exploration activity reduced  Norwegian government curtailments, shut-ins of some higher cost production and extended maintenance programs have modest impact on near-term production volumes HSE performance stable, introduced COVID-19 response plan to support employees, suppliers and communities  Safety performance stable, with 0.7 for LTIF, 2.3 for TRIR and 1.95 for PSER  Introduced a process safety dashboard, reporting on 10 leading process safety indicators on monthly basis for operated activities  Targeted COVID-19 response plan put in place: increased screening capability and introduced employee counselling service; targeted support for key supply chain partners and provided access to global medical provider; support for international relief fund and employee social initiatives across the business

FINANCIAL SUMMARY

Neptune Energy Q1 2020 & YTD Q1 2019 & YTD Total daily production (kboepd) (note c) 162.1 151.8 Average realised oil price ($/bbl)(note a,c) 47.1 58.5 Average realised oil price including hedging ($/bbl)(note b,c) 49.2 57.8 Average realised gas price ($/mcf)(note a,c) 2.9 6.5 Average realised gas price including hedging ($/mcf)(note b,c) 4.1 6.5 EBITDAX ($m) (RBL basis) (note d) 322.9 451.0 Operating costs ($/boe) 8.9 10.1 Operating cash flow ($m) 355.2 362.3

a) Average realised prices are stated before the impact of hedging. b) Average realised prices are stated after the impact of hedging. c) Production and realised price figures are for wholly owned affiliates and equity accounted affiliates. d) EBITDAX (excluding our share of net income from Touat), as defined by the RBL and shareholder agreement.

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Jim House, Chief Executive Officer “Despite the challenges posed by the COVID-19 pandemic, Neptune’s operational performance in the first quarter of the year was

• strong. Our resilience plan and hedging activity mitigated weaker commodity prices, resulting in a robust financial performance.

“We have taken decisive action across the business to increase liquidity and reduce cost, while preserving long-term value. We continue to review our business to identify opportunities to reduce operating expenditure further and focus on value over volume. “The second quarter of the year is likely to be more challenging and we expect production to be lower, reflecting planned maintenance and development-related shutdowns and weaker commodity prices. “We remain mindful of the impact of the pandemic and have put in place measures to support our people, our suppliers and the communities in which we operate.” GROUP OVERVIEW Despite the challenges of COVID-19 and weaker commodity prices, Neptune delivered a strong operational and robust financial performance in the first quarter of 2020. Group production for the period averaged 162.1 kboepd, which is above our full year guidance range, with strong results in Norway, the UK, Indonesia and Egypt. Since the end of the quarter, the Touat plant has reached plateau capacity and project handover is being finalised. There has been limited impact from COVID-19 on our operations. However, disruption to the global supply chain has slowed down some project activities. We continue to monitor the situation closely to ensure the wellbeing of our people and operational

• continuity. Production efficiency at our operated assets was 86% in the first quarter.

Health and safety is our highest priority and we maintained a good performance in the first quarter, with both our key metrics, lost time injury frequency (LTIF) rate and total recordable incident rate (TRIR), stable. Our process safety event indicator improved further and is below target. While the weakness in commodity prices is a significant challenge for the oil and gas industry, Neptune is well-positioned, with significant available liquidity, low operating costs and high levels of hedging. To protect our balance sheet, we announced cost reduction measures of $300-400 million for 2020 across operating costs, G&A and capex. We have made good progress in implementing these measures and a significant proportion of these reductions has been realised. We continue to evaluate our business to identify further opportunities to reduce expenditure. Our project pipeline represents the main area of immediate cost reductions. In addition to the impact of COVID-19 on some of our schedules, we have elected to slow the pace of investment on certain other projects, which will smooth investment across 2020-22. While this will push back first production at some projects, the overall impact on production is limited, with reduced growth in forecast Group production in 2021 and 2022. First production from the Njord and Duva projects is now expected in the second half of 2021, with Fenja due onstream in early

• 2022. First oil from the Seagull project is likely to be deferred until late 2022. As previously guided, the Merakes field is expected
• nstream in mid-2021. The P1 Gjøa project is largely unaffected.

In May 2020, we agreed to terminate the agreement to acquire Edison E&P’s UK and Norwegian subsidiaries from Energean Oil &

• Gas. This will further enhance our near-term liquidity by ~$460m and enable us to focus on our pipeline of other growth
• pportunities.

We have also identified savings within our exploration programme and have deferred several wells into 2021. Our remaining drilling programme in 2020 includes the Sillimanite South (Netherlands) and Dugong (Norway) exploration wells. Reductions within our resilience plan are partially offset by an increase related to higher drilling costs for successful wells and seismic acquisition costs in Egypt, but are expected to deliver a net $20 million reduction in our exploration spend to around $125 million in 2020. In 2020, our drilling programme has achieved positive results with successful wells in Norway, the UK and Germany. The recently completed Adorf-Z15 and Ringe-6 wells in Germany will be brought onstream in 2020. In the UK, we continue to evaluate the results from the material Isabella discovery announced in March.

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Reflecting strong production during the period and our efficiency programmes, operating costs in the first quarter were $8.9/boe and are now expected to average less than $10/boe for the full year. During the first quarter, average commodity price realisations were substantially weaker than in 2019, although this weakness was partially offset by hedging activity. Including hedging gains, average realisations were $49.2/bbl for oil, $7.4/mcf for LNG and $4.1/mcf for gas. For the remainder of 2020, we have hedges covering 68% of post-tax operating cash flows. We are less hedged for

• il, but did increase our hedged oil positions for the second and third quarters of 2020.

Post-tax operating cash flow of $355 million in the first quarter of 2020 was 2% lower than the first quarter of 2019. Cash flow fully funded our investment activity in the period, including $233 million in development capex and $39 million in exploration. The majority of investment was in our projects in Norway. Development capex is now expected in the range of $700-800 million in 2020. The Norwegian government has submitted proposals to provide tax relief in 2020 and 2021, allowing full write-offs for investments and tax refunds for losses in both periods. We await the final legislation to assess the on our business. Net debt (excluding Subordinate Neptune Energy Group Limited loan and Touat Project loan) at the end of the first quarter was $1.5 billion. Our net debt to EBITDAX (excluding our share of net income Touat) leverage ratio increased to 0.99 times reflecting lower 12-month rolling EBITDAX. We expect our leverage ratio to increase to around 1.6 times at the end of 2020. After the end of the first quarter, we successfully redetermined our RBL facility, increasing the borrowing base from $2.0 billion to $2.3 billion. The reduction from previous guidance reflects the agreement to terminate the acquisition Edison E&P’s UK and Norwegian subsidiaries from Energean Oil & Gas. The facility was upsized and increased by $0.6 billion to $2.6 billion. In a challenging environment this was an exceptional result, reflecting the quality and value of our assets, as well as the support from

• ur core banks. Available and undrawn headroom under the RBL of $1.6 billion, combined with cash of $98 million, provides us with

liquidity of $1.7 billion. We have taken significant steps to support our people, our suppliers and our local communities through the COVID-19 pandemic. These include reducing non-critical activities and altering shifts to minimise crew levels, implementing a screening process for

• ffshore workers and requesting that office-based staff work from home.

We introduced a mental health counselling service for employees and contractors, and provided suppliers with access to our global medical provider. We have assessed our key supply chain partners so that we can provide targeted support. Our efforts to help local communities include donating to the emergency appeal of the International Committee of the Red Cross, providing PPE and food to hospitals and community organisations, and supporting employee volunteering initiatives. In March we further strengthened our management team with the appointment of Alexandra Thomas, who has joined the company as UK Managing Director. Outlook After a strong start to 2020, production is expected to be lower in second quarter reflecting planned maintenance and development- related shutdowns, partially offset by higher production at Touat and the Netherlands. Our full year production guidance remains unchanged at 145-160 kboepd and includes the expected impact of mandatory production cuts imposed in Norway, the withdrawal from the Energean transaction and a focus on value over volume. Since March 2020, commodity prices moved sharply lower. While we have a high hedge ratio, particularly on gas, earnings and

• perating cash flows in the near-term are likely to be lower than reported in the first quarter. Together with hedging gains, the

reduction in operating cash flow is fully mitigated in 2020 by our resilience plan and lower expected taxes. We retain significant available liquidity to fund our project pipeline and expect to achieve positive free cash flow for the year. Due to our strong operating performance and progress made delivering our resilience plan, we now expect operating costs to average less than $10/boe for the full year. Our development capex guidance for the year is also reduced to $700-800 million and

• ur exploration spend is expected to be around $125 million.

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OPERATING REVIEW Health and safety Our health and safety performance remained stable across all our countries in the first quarter of the year. There were no serious personal injuries and our LTIF rate was 0.7 per million hours worked, slightly above our target of 0.6. Our TRIR was 2.3 per million hours worked versus our new target of 2.0, which we reduced to promote continual improvement. Our aim for our safety performance is to demonstrate top quartile performance relative to our peers. These figures include cooperated joint venture activities. In recent months, we have increased our focus on health and safety, reiterating the need for safety leadership and to follow the right procedures despite changes to working practices related to COVID-19. Our process safety event rate (PSER) KPI for the first quarter improved to 1.95 per million hours worked, which is below our target of 2.1. A process safety dashboard was introduced in the first quarter of this year, reporting on 10 leading process safety indicators on a monthly basis across all our operated activities. Norway Production In Norway, production in the first quarter increased by 5.2 kboepd from the fourth quarter of 2019 to 68.1 kboepd, reflecting start- up of the Troll C Gas Module in February (resulting in increased Fram production), recommencement of the Mossmoran Ethylene plant in Scotland, which improved NGL recovery from Gjøa and a general strong operational performance. Production from Snøhvit was reduced in March as the plant faced operational challenges caused by a small increase in mercury levels in the process. This is expected to be resolved in the second quarter. Production in the second quarter is expected to be lower due to a shutdown at Gjøa in May to install the topside module for the Nova tie-in. Planned shutdowns at Fram, Ivar Aasen, Gjøa and Snøhvit have been delayed until 2021. The Norwegian Ministry of Petroleum and Energy has also announced an industry wide oil production cut. The policy will reduce production by 250 kboepd in June and by 134 kboepd in the second half of 2020. The cuts will be distributed across individual oil fields, with gas fields, including Gjøa, exempt. Due to our gas-weighted portfolio, we anticipate the policy will have a limited impact

• n our production in Norway. The Norwegian government has also submitted proposals to revise tax relief in 2020 and 2021,

allowing full write-offs for investments and tax refunds for losses in both periods. Operating costs for the first quarter remained low at $6.5/boe. Development and exploration During the first quarter we continued to progress our development projects in Norway. Since the end of the period we have agreed resilience plans and revised project schedules with our partners. Due to the impact of COVID-19 and a slower pace of development, the operator, Equinor, has advised that the Njord development has been delayed. First production is now anticipated in the second half of 2021. As a consequence, the Neptune-operated Fenja project, which is being developed as a tie-back to Njord, is expected to come

• nstream in the first quarter of 2022. In April 2020, we commenced the world’s first dual drilling operation from an

integrated subsea template. The results from these two geo-pilot wells will be used to optimise placement of the development wells. The main subsea and development drilling campaigns have been deferred until 2021. The schedule for the Gjøa P1 project is largely unaffected. However, the Duva project, which is being developed as a tie-back to the Neptune-operated Gjøa platform, will see a delay in first oil of four to six months. During the first quarter, the first development well on Gjøa P1 was drilled, with drilling set to continue at Gjøa P1 and Duva throughout 2020 and into 2021. Further topside work for the Duva project, scheduled for the second half of 2020, has been deferred until 2021 due to COVID-19 related restrictions. First production from Duva is now anticipated in the third quarter of 2021. The Gjøa P1 project remains on schedule for first production in late 2020 or early 2021.

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At our existing production assets, the Brage A-36B well commenced production in February 2020. The Gudrun A-15 and Brage A- 12C wells are due onstream in the second quarter. However, start-up of the Gudrun A-8 well has been delayed. A three-well programme on Askaladd was completed 60 days ahead of schedule. These wells increase production capacity at Snøhvit. During the first quarter, Neptune announced an oil discovery at the Sigrun East prospect. Neptune has a 25% working interest in the discovery, which could be developed as a sub-sea tie-back to the non-operated Gudrun field. The Grind exploration well was dry. In January 2020 we were awarded a further 13 licences in Norway, including four as operator. Netherlands Production During the first quarter, production in the Netherlands averaged 19.2 kboepd. Production was lower in February and March due to an unplanned shutdown of the L10 platform and delays to a compressor upgrade project on G17, but was partially mitigated by production from the new E17a-A6 and L5A-D4 wells, a strong performance from K2b-A and start-up of the Sillimanite field. The L10 platform was shut down for 28 days for repairs after an inspection identified corrosion. Production at the beginning of the second quarter has improved to planned levels. Operating costs for the first quarter were $13.1/boe, reflecting lower transportation, logistics and staff costs and favourable FX movements. Development In February, we brought onstream the high-pressure high-temperature L5a-D4 well at a rate of 50 mmcfpd, with the well performing in line with expectations. The Sillimanite field was also successfully brought onstream with the first well contributing around 0.5 kboepd net to Neptune. A second development well has been completed and is expected to come onstream in the second quarter. The K9ab-A4 development well has been delayed until 2021. In April, we announced that Gasunie and Eneco, had joined the PosHYdon Hydrogen pilot project. Gasunie manages gas storage and transportation infrastructure in the Netherlands and northern Germany and is involved in several onshore hydrogen pilot

• projects. Eneco will supply simulated wind data from its offshore wind farm, Luchterduinen, to support the project, which aims to

integrate three energy systems in the North Sea: offshore wind, offshore gas and offshore green hydrogen. The offshore campaign to decommission the L10-C/D/G platforms was completed in April and below budget. The platforms have been transported to the demolition contractor’s yard in the Netherlands for dismantling and recycling. UK Production Production in the UK averaged 19.3 kboepd in the first quarter with high levels of production efficiency. Production benefitted from high export availability and production efficiency levels at Cygnus and a contribution from our UK interest in the Sillimanite field. Shutdown plans for Cygnus are currently under review due to rescheduling of the major regional pipeline shutdowns. Operating costs for the first quarter were lower at $7.4/boe reflecting higher production and cost efficiencies. Development and exploration At Cygnus, as a result of good reservoir performance, the gas compression project has been deferred until the first quarter of 2021. Evaluation of potential appraisal and infill locations is ongoing. The re-route of Shearwater gas to St Fergus has been delayed until mid-2021, reducing expected blend gas constraints in the second half of 2020. Discussions to execute a new blend gas agreement are expected to conclude in mid-2020. Medium-term solutions to the blend gas issue continue to progress positively, with potential solutions in place by the end of 2021. In April 2020, an industry consultation was published, recommending widening the existing Wobbe index upper and lower limits. This would enable us to export Cygnus gas without the need for blending.

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Due to the impact of COVID-19 on our supply chain and logistics, first oil from the Seagull development is likely to be impacted by 12-15 months until the fourth quarter of 2022. The ETAP topside strengthening and installation programme is expected to commence in early 2021. During the first quarter, Neptune announced a material oil, gas and condensate discovery at the Isabella prospect. Post-well evaluation is underway to understand appraisal requirements. Neptune has a 50% interest in Isabella. Germany Production Production in Germany averaged 17.3 kboepd in the first quarter of 2020. Production was lower than expected due to customer

• fftake constraints, which reduced volumes from the Altmark field in January and February. An extension to the Altmark offtake

agreement has been agreed and will extend operations until the end of 2021. Due to the change in Group conversion factors announced at our full year results, reported production in Germany increased by approximately 6 kboepd. The change impacts low calorific gas produced from the Altmark field et al, but has no impact on profitability. Operating costs for the first quarter, excluding royalties, were $13.9/boe, reflecting cost saving initiatives and the change in conversion factors. Due to low commodity prices, operations in Bentheim and a field in the Hamburg region will cease production. Development and exploration As part of our resilience plan we have reduced workover activities at the Rühlermoor field and deferred the Kietz-6, Rӧmerberg-6 and two Bramberge wells until 2021. In early 2020, we sanctioned refurbishment of the Bramberge surface facilities, with the programme expected to complete in 2023. In March, we announced that the Schwegenheim-1 exploration well had made a small oil discovery in a secondary target. The well flowed oil to surface during initial testing and has been suspended pending an application for a production licence and a long-term test. In April, we announced gas and oil discoveries at the Neptune-operated Adorf-Z15 and Ringe-6 wells. The Adorf-Z15 well was successfully tested at indicative flow rates of up to 1.7 kboepd. A gas processing plant will be constructed, with production expected to commence before the end of this year. The Ringe-6 well confirmed a western extension of the Ringe oil field and has been tied into existing infrastructure. The well commenced production at 500 bopd. North Africa Algeria Production During the first quarter production at Touat continued to ramp-up towards plateau, averaging 7.5 kboepd for the period. The Touat plant is now operating at plateau capacity and final plant handover to the GTG operational team is being finalised. Three workovers have been successfully completed. Operating costs in Algeria were in line with expectations, averaging $9.2/boe. Development Tendering for the second Touat development phase has been deferred until 2021. Egypt Production In Egypt, production remained strong averaging 5.2 kboepd in the first quarter, reflecting early production from Assil-9, a strong performance from Alam El Shawish, gas lift optimisation at the Ashrafi field and a contribution from previously non-producing wells.

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Operating costs in Egypt were $10.3/boe in the first quarter. Development We completed five development wells during the first quarter, with no further wells planned in 2020. The Assil-9 gas well has performed above expectations. Four development wells have been deferred until 2021. A workover campaign to initiate production from nine existing shut-in wells has commenced. We formally signed the North West-El Amal concession in February. The acquisition of 3D seismic was completed at the beginning

• f the second quarter and data processing is underway.

The Bahga C101-H and Assil C105 exploration wells have been deferred until 2021. Asia Pacific Indonesia Production Production in Indonesia averaged 25.5 kboepd in the first quarter of 2020. This was an increase of 3.2 kboepd from the fourth quarter of 2019, reflecting higher entitlement production following the reimbursement of the Saka development carry and the front loading of production ahead of a planned extended shutdown of the Jangkrik FPU in May. With the Merakes development deferred until 2021, the shutdown has been postponed and delivered volumes for the remainder of 2020 are expected to average a lower rate. We have also been notified by our offtake counterparties of a downwards quantity tolerance adjustment of 3.5 cargoes to our supply schedule in 2020. This is equivalent to 10% of the agreed contracted volumes, but may be partially mitigated through the potential sale of two cargoes on the spot market. In mid-February, the second pipeline tie-in project was successfully completed reducing requirements for C3/C4 purchases. Operating costs in the first quarter averaged $8.4/boe, reflecting higher production, a reduction in blending costs, delayed maintenance and lower cost outturns. Development and exploration Due to the impact of COVID-19, the operator of the Merakes development declared force majeure in March 2020. Development activities have been suspended, with operations expected to recommence in early 2021. Merakes first gas is now scheduled in mid-

• 2021. Planning for the Maha development and West Ganal exploration programmes are currently being reviewed.

Australia In Australia, we sponsored the acquisition of new 3D seismic via a multiclient survey covering the Petrel field and surrounding

• acreage. The new data, which is currently being processed, will help delineate the field and de-risk development opportunities.

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Summary of production by area - wholly owned affiliates

Q1 2020 & YTD Q1 2019 & YTD Norway 24.9 26.9 UK 18.9 16.3 The Netherlands 17.0 23.0 Germany 11.1 7.3 North Africa 3.7 2.8 Asia Pacific 4.0 2.7

Total Gas production (kboepd)

79.6 79.0

Gas production for sale as LNG (kboepd)

Norway 13.4 12.5 Asia Pacific 20.8 16.6

Total Gas production for sale as LNG (kboepd)

34.2 29.1

Liquid production (kbpd) (note 1)

Norway 29.8 32.8 UK 0.4 0.4 The Netherlands 2.2 2.7 Germany 6.2 5.5 North Africa 1.5 1.6 Asia Pacific 0.7 0.7

Total Liquid production (kbpd)

40.8 43.7

Total production (kboepd)

Norway 68.1 72.2 UK 19.3 16.7 The Netherlands 19.2 25.7 Germany 17.3 12.8 North Africa 5.2 4.4 Asia Pacific 25.5 20.0

Total production (kboepd)

154.6 151.8

1) Liquid includes oil and condensate and other natural gas liquids.

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Summary of production by area – equity accounted affiliates

Q1 2020 & YTD Q1 2019 & YTD

Gas production (kboepd)

North Africa 7.3

• Total Gas production (kboepd)

7.3

• Liquid production (kbpd) (note 1)

North Africa 0.2

• Total Liquid production (kbpd)

0.2

• Total production (kboepd)

North Africa 7.5

• Total Gas production (kboepd)

7.5

• 1) Liquid includes oil and condensate and other natural gas liquids.

Summary of production by area – wholly owned and equity accounted affiliates

Q1 2020 & YTD Q1 2019 & YTD

Total production (kboepd)

Norway 68.1 72.2 UK 19.3 16.7 The Netherlands 19.2 25.7 Germany 17.3 12.8 North Africa 12.7 4.4 Asia Pacific 25.5 20.0

Total production (kboepd)

162.1 151.8

1) Liquid includes oil and condensate and other natural gas liquids.

Neptune Energy Group Midco Limited Report for the period ended 31 March 2020 12

Financial review

This report includes the Group results for the three months ended 31 March 2020. Results of operations

US$ millions 3 months ended 31 March 2020 3 months ended 31 March 2019 Revenue 479.7 621.1 Operating profit (note a) 155.3 271.3 Profit before tax 118.4 206.6 Taxation (71.4) (153.9) Net profit 47.0 52.7 EBITDAX (RBL basis) (note b) 322.9 451.0 Cash flow from operations, after tax 355.2 362.3 Adjusted development cash capital expenditure (note c) 242.2 168.7 Net debt (book value) (RBL basis) (note d) 1,462.9 1,112.8 Net Debt/ EBITDAX (RBL basis) (notes d and e) 0.99 x 0.50 x

a) Operating profit comprises current operating income after share in net income of entities accounted for using the equity method and is stated before tax and finance costs, but after mark- to-market on commodity contracts and non-recurring items. b) EBITDAX (as defined by the RBL and Shareholder agreements to exclude our share of net income from Touat). EBITDAX comprises net income for the period before income tax expense, financial expenses, financial income, other operating gains and losses, exploration expense and depreciation and amortisation. c) Includes capital expenditure of $9.4 million for the period to 31 March 2020 (2019: $15.9m) in respect of the Touat project, held by a joint venture company which Neptune accounts for under the equity method. d) Net debt excludes Subordinated Neptune Energy Group Limited Loan and Touat project finance facility as defined by the RBL and Shareholder agreements. e) EBITDAX is based on a 12-month rolling average value of $1,472.1 million (2019: $2,236.8 million), as defined by the RBL and Shareholder agreements.

Total sales for the three months ended 31 March 2020 were $479.7 million (2019: $621.1 million), reflecting total production of 14.1 mmboe (2019: 13.7 mmboe) (for wholly owned affiliates) and realised prices, before and after hedging, as shown in the table

• below. The principal reason for the lower sales in the first quarter of 2020 was due to lower commodity prices offset only

marginally by an increase in production. The Brent crude price averaged $50.8 (2019: $63.8) per barrel for the three months ended 31 March 2020 and our average realised

• il price (pre hedging) was $47.1 per barrel (2019: $58.5) for the same period. The combination of weakening demand resulting

from the COVID-19 global pandemic and the breakdown of the OPEC+ production alliance combined caused a significant drop in crude oil prices in the first quarter of 2020. LNG sales prices are linked to a combination of movements in oil and gas market prices, depending on the contract. The average realised gas price was $2.9 per mcf (pre hedging) and $4.1 per mcf (post hedging) for the three months ended 31 March 2020. This compared with $6.5 per mcf (pre hedging) and $6.5 per mcf (post hedging) for the same period in 2019. The European gas market continued to face volatility over the first quarter of 2020 as a sizeable storage overhang from 2019 and mild winter weather combined to further pressure prices.

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Realised prices data:

3 months to 31 March 2020 3 months to 31 March 2019 Excluding impact of hedging: Average realised gas price ($/mcf) 2.9 6.5 Average realised LNG price ($/mcf) 7.4 9.0 Average realised oil price ($/bbl) 47.1 58.5 Average realised price, other liquids ($/bbl) (note a) 21.3 42.2 Including impact of hedging: Average realised gas price ($/mcf) 4.1 6.5 Average realised LNG price ($/mcf) 7.4 9.0 Average realised oil price ($/bbl) 49.2 57.8 Average realised price, other liquids ($/bbl) (note a) 21.3 42.2 a)

Other liquids includes condensate and other natural gas liquids

b)

Realised price figures are for wholly owned affiliates and equity accounted affiliates

Operating costs were $124.7 million (2019: $138.4 million) for the three months to 31 March 2020 and our average operating cost per boe produced was $8.9/boe compared with $10.1/boe for 2019. Operating costs for the purpose of per boe expense are reduced by $15.7 million (2019: $9.1 million increase) for the three months ended 31 March 2020 to exclude changes in the value

• f under-lifted entitlement to production and to net-off income from tariffs and services which serve to recover costs.

The depreciation and amortisation expense was $147.5 million (2019: $170.3 million). The charge represents $10.5/boe produced compared with $12.5/boe produced for the three months ended 31 March 2019. The lower charge in 2020 compared to 2019 reflects the increase in reserves due to field revisions and extensions principally in Norway, the UK and the Netherlands that

• ccurred later in 2019.

Exploration expense for the period was $22.1 million (2019: $7.5 million) which includes costs incurred on G&G studies to review strategic growth opportunities, as well as costs associated with unsuccessful well evaluations. The higher 2020 charge compared with 2019 was due to $11.5m of costs for an unsuccessful well evaluation in Norway and higher exploration costs in the UK and higher seismic costs in Australia. General and administration expense of $13.3 million (2019: $41.0 million) for the three months to 31 March 2020 consists primarily

• f costs that are not directly incurred for production or capital projects (including exploration), such as staff employment costs

related to corporate functions and selling expenses, office costs and fees for services provided to us. The company allocates a proportion of salaries and other costs to projects; a revised cost allocation process was adopted from the second quarter 2019, hence the general and administration expenses were higher in the first quarter of 2019. In addition, general and administration has also fallen due to our cost efficiency programmes across the business and benefitted from the recognition of R&D recharge credits in Norway due to the high capital expenditure in the period. Share in net income of entities accounted for under the equity method was $9.4 million (2019: $0.6 million) for the three months ended 31 March 2020. This represents the Touat joint venture, which commenced production in September 2019 of $9.2 million (2019: $0.3 million) and tariff income in a Dutch pipeline interest of $0.2 million (2019: $0.3 million). Other operating gains/(losses) were a loss of $7.2 million (2019: loss $2.3 million) for the three months ended 31 March 2020. The 2020 loss includes net mark-to-market loss on currency and commodity derivative contracts of $11.0 million (2019: gain $14.6 million), a restructuring provision release of $0.3 million (2019: charge $17.8 million), and other gains of $3.5 million (2019: gains $0.9 million). The restructuring charge in 2019 predominantly related to group reorganisation costs in Germany. The Group’s operating profit for the period to 31 March 2020 was $155.3 million (2019: $271.3 million) before net finance costs. EBITDAX (on an RBL basis) for the period was $322.9 million, compared with $451.0 million for the period ended 31 March 2019. The decrease in EBITDAX principally reflects lower realised commodity prices in the first three months of the year.

Neptune Energy Group Midco Limited Report for the period ended 31 March 2020 14

Net financing expenses were $36.9 million (2019: $64.7 million) for the period. The majority of this change relates to the net foreign exchange movement being a gain of $9.4 million in 2020 and a loss of $21.2 million in 2019. The net foreign exchange gain arises on the revaluation of loans and working capital balances across the Group and is principally impacted by the exchange rates for Euros, Norwegian Krona, Sterling and US Dollars. The Group’s total tax charge for the three months to 31 March 2020 is $71.4 million (2019: $153.9 million), comprising a current tax charge for the period of $24.0 million (2019: $140.5 million) and a deferred tax charge for the period of $47.4 million (2019: $13.4 million). The total tax charge for the period represents an effective tax rate of 60% (2019: 74%). The effective tax rate is lower than the Group’s weighted average statutory rate of 68% due to hedging gains in Norway being taxable at the standard rate of corporate tax rather than the full statutory rate applicable to E&P activities, the utilisation of tax losses on which no deferred tax had been provided both of which are partially offset by prior year adjustments following the filing of tax returns and the closing out of historic assessments during the quarter. Net income for the three months ended 31 March 2020 was $47.0 million (2019: $52.7 million) on a reported basis. Hedging Group policy is to seek to reduce risk related to commodity price fluctuations by using hedging instruments to set a floor for the sales realisations for a proportion of forecast revenues on a rolling basis, with reducing levels of hedging for each of the next three

• years. The Group actively manages this hedging programme using, among others, swaps and options.

As at 31 March 2020, the approximate share of post-tax production (which adjusts for different tax rates on physical sales and hedge gains and losses, meaning that effective post-tax hedges can be achieved through hedging contracts for volumes which may be significantly less than anticipated sales) hedged for future periods is shown in the table below. For oil, weighted average downside protection is $43.9/barrel for the remainder of 2020 with upside capped at around $48.5/barrel in 2020. For gas, hedging provided weighted average floor prices of $5.5/mmbtu for 2020, $5.6/mmbtu for 2021 and $5.5/mmbtu for 2022, with upside caps at $6.7/mmbtu, $6.7/mmbtu and $5.6/mmbtu respectively. Aggregate post-tax hedge ratio (as at 31 March, 2020):

2020 2021 2022 Oil 47%   Gas 90% 65% 49% Total weighted average 68% 29% 19%

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 means that effective post-tax hedges can be achieved through hedging contracts for volumes which may be significantly less than anticipated sales. 3) Hedge percentages are based on total Group forecast production volumes including Algeria, but exclude the likely impact of the recent Edison acquisition announcement which is yet to complete.

The fair value of our commodity derivative instruments at 31 March 2020 was a net asset of $419.8 million (31 December 2019: $182.7 million asset), of which $278.4 million relates to contracts that mature during 2020. Cash flow Operating cash flow, after cash taxes, for the three months to 31 March 2020 was $355.2 million (2019: $362.3 million). Cash taxes were $37.3 million (2019: $70.6 million) and largely relate to Norwegian taxes. The effective rate of cash tax as a percentage of pre- tax operating cash flow was 10% (2019: 16%).

Neptune Energy Group Midco Limited Report for the period ended 31 March 2020 15

Capital expenditure Cash capital expenditure for the period to 31 March 2020, was $271.9 million (2019: $155.8 million), including $39.1 million (2019: $3.1 million) of capitalised exploration expenditure. The 2020 figure includes expenditure in Norway on Njord, Duva/Gjøa P1 and Fenja and expenditure in Indonesia on the Merakes development project. 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 $12.5 million in the period.

US$ millions 3 months ended 31 December 2020 3 months ended 31 December 2019 Investing cash flows: Development capex (note a) 232.8 152.7 Exploration capex 39.1 3.1 Total cash capital expenditure 271.9 155.8

a) Includes Saka carry reimbursement of $2.5 million (2019: $15.6 million) b) Capex figures are for wholly-owned affiliates only

Total exploration expenditure comprised the $39.1 million (2019: $3.1 million) cash capex and $10.6 million (2019: $7.5 million) expensed in respect of G&G and seismic costs. Development cash capex was $232.8 million (2019: $152.7 million). The majority of expenditure was in Norway on the Njord, Duva/Gjøa P1 and Fenja project as well as progressing the Merakes project in Indonesia. We incurred $10.8 million (2019: $9.6 million) on decommissioning cash expenditure in the three months to 31 March 2020, this was principally in the UK, the Netherlands and Germany. Financing and liquidity Management’s financial strategy is to manage Neptune’s capital structure with the aim that, across the business cycle, net debt (excluding vendor loans) to EBITDAX (excluding our share of net income from Touat), as defined by the RBL and shareholder agreement, remains modest. The ratio, at the end of the period, equals 0.99x. The ratio equalled 0.93x at the year-end of 2019. We funded our business with cash generated from operations. At 31 March 2020, we had the following debt outstanding:  $750 million drawn under the $2 billion RBL committed RBL facility, which matures in 2024;  $850 million 6.625% senior notes due 2025;  $108 million 7.250% subordinated loan due to Engie in 2024;  $261 million 8.000% loan due 2023 (drawn under Touat vendor loan project finance facility with Engie);  $21 million drawn under short-term borrowing facilities. At 31 March 2020, our cash balance totalled $97.5 million (31 December 2019: $85.4 million) and our available and undrawn headroom under the RBL was $1.2 billion. We also had $100 million of letters of credit outstanding, of which $9 million were drawn down under an ancillary facility under the RBL. Our weighted average cost of borrowing for the Group equalled 5.9%. Our Corporate Credit Rating with Moody’s, S&P and Fitch remain at Ba3, BB- and BB respectively. However the ratings has been placed on review with Moody’s and on negative outlook with S&P and Fitch, as a result of the short term industry outlook. Despite the challenging market environment, we will continue to seek to strengthen these ratings over time. All debt, with the exception of the RBL, is carrying a fixed interest rate. A significant portion of the RBL was swapped into fixed rate debt in early 2018. As at 31 March 2020, 82% of the debt portfolio was fixed reducing Neptune’s exposure to increases in the USD Libor interest rate.

Neptune Energy Group Midco Limited Report for the period ended 31 March 2020 16

Financial condition Operating cash flows of $355.2 million (2019: $362.3 million) more than covered investing cash flows of $281.5 million (2019: $161.7 million) and after financing costs and net debt repayment of $60.5 million (2019: $226.3 million) during the period resulted in a net cash inflow of $13.2 million for the period to 31 March 2020 (2019: $25.7 million outflow). We ended the period with gross interest-bearing debt of $1,929.6 million (book value) and net debt on an RBL basis, (excluding Subordinated Neptune Energy Group Limited loan and Touat project finance facility) of $1,462.9 million. This represents a net debt to EBITDAX (excluding Touat cash flows) ratio of 0.99x for the 12 months ending 31 March 2020 (2019: 0.50x). Outlook After an encouraging start to 2020, we anticipate production and earnings will move lower in the near-term, reflecting planned maintenance and lower commodity prices. Our hedging and resilience plan are expected to mitigate lower cash flows during this period. We expect to make further progress realising cost reductions identified in our resilience plan in the second quarter and continue to review opportunities to reduce expenditure further. In April, the Norwegian government announced proposals to cut oil production from June 2020 until the end of the year and to revise tax relief in 2020 and 2021. We expect a limited impact on production and our full year production guidance remains unchanged at 145-160 kboepd. We continue to review the impact of the Norwegian tax proposal. Operating costs declined to $8.9/boe in the first quarter and are now expected to average less than $10/boe for the full year. Development capex guidance has also been reduced to $700-800 million. No COVID-19 costs were incurred in the results for the three months ended 31 March 2020. In 2020, the organisation will continue to monitor significant COVID-19 costs as part of its business as usual reporting. We will continue to focus on the safety and wellbeing of our employees and contractors around the world. Risks and uncertainties Investment in Neptune involves risks and uncertainties, these are summarised in detail in the Neptune Energy 2019 Annual Report and Accounts on page 43. As an oil and gas, exploration and production company, exploration results, reserve and resource estimates, and estimates for capital and operating expenditures involve inherent uncertainties. A field’s production performance may be uncertain over time. The Group is exposed to various forms of financial risks, including, but not limited to, fluctuations in oil and gas prices, currency exchange rates, interest rates and capital requirements. The Group is also exposed to uncertainties relating to political risks, the international capital markets and access to capital and this may influence the speed with which growth can be accomplished. Going concern Given 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.

While the short-term outlook is uncertain due to COVID-19 and the subsequent fall in oil prices, we believe the longer-term outlook is positive for the gas sector and we are well positioned to benefit from the transition to a lower-carbon energy market. Our low- cost projects, long-life production and strong balance sheet provides resilience for the Group against softer commodity prices. Our emergency pandemic plan has been implemented and working practices changed to ensure operational continuity. We have also put in place mitigation plans for our projects and will continue to evaluate supply chains for impacts. In reaching the conclusion that the going concern basis is appropriate, we have stress tested future cash flow forecasts and covenant compliance for the Group to evaluate the impact of plausible downside scenarios. These include scenarios that reflect current market conditions and updated short term commodity price forecasts. Additionally, we considered our planned cost reductions in response to lower commodity prices, which provide further resilience against softer commodity prices. We have also performed reverse stress testing to inform our judgement. Under all plausible scenarios, it was concluded that the Group retains sufficient liquidity and that the going concern basis remains appropriate.

Neptune Energy Group Midco Limited Report for the period ended 31 March 2020 17

NEPTUNE ENERGY GROUP MIDCO LIMITED UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS For the three months ended 31 March 2020

Neptune Energy Group Midco Limited Unaudited Condensed Consolidated Financial Statements For the three months ended 31 March 2020

Neptune Energy Group Midco Limited Report for the period ended 31 March 2020 18

Unaudited Condensed Consolidated Statement of Profit and Loss

Group In millions of US$ Notes Three months ended 31 March 2020 Three months ended 31 March 2019 Revenue 3 479.7 621.1 Cost of sales (291.2) (299.6) GROSS PROFIT 188.5 321.5 Exploration expenses (22.1) (7.5) General and administration expenses (13.3) (41.0) Share of net income from investments using equity method 9.4 0.6 OPERATING PROFIT AFTER EQUITY ACCOUNTED INVESTMENTS 3 162.5 273.6 Other operating (losses)/gains 4 (7.2) (2.3) OPERATING PROFIT BEFORE FINANCIAL ITEMS 155.3 271.3 Finance income 12.3 1.7 Finance costs (49.2) (66.4) PROFIT BEFORE TAX 118.4 206.6 Taxation 5 (71.4) (153.9) NET PROFIT 47.0 52.7

All profits and losses arise as a result of continuing operations.

Unaudited Condensed Consolidated Statement of Other Comprehensive Income

Group In millions of US$ Notes Three months ended 31 March 2020 Three months ended 31 March 2019 Profit/(Loss) for the period 47.0 52.7 Other Comprehensive Income: Items that may be reclassified to the Income Statement: Hedge adjustments net of tax (note 1) 12 180.3 37.4 Foreign currency translation (261.1) 53.5 (80.8) 90.9 OTHER COMPREHENSIVE INCOME (80.8) 90.9 OTHER COMPREHENSIVE PROFIT FOR THE PERIOD, NET OF TAX (33.8) 143.6

1) Income tax related to hedge adjustments is $59.3 million charge (2019: $3.0 million) and is shown net of amounts reclassified to profit or loss or included in finance costs.

Neptune Energy Group Midco Limited Unaudited Condensed Consolidated Financial Statements For the three months ended 31 March 2020

Neptune Energy Group Midco Limited Report for the period ended 31 March 2020 19

Unaudited Condensed Consolidated Statement of Financial Position

Group In millions of US$ Notes 31 March 2020 31 December 2020 NON-CURRENT ASSETS Goodwill 6 549.1 640.8 Intangible assets 7 166.1 150.9 Property, plant and equipment 8 4,172.7 4,430.8 Derivative instruments 12 120.4 74.9 Investments in entities accounted for using the equity method 626.0 604.7 Other non-current assets 12 98.2 110.6 Equity instruments 12 18.8 19.3 Deferred tax assets 630.4 691.0 TOTAL NON-CURRENT ASSETS 6,381.7 6,723.0 CURRENT ASSETS Derivative instruments 12 315.3 147.4 Trade and other receivables 12 711.9 651.9 Inventories 59.7 60.4 Cash and cash equivalents 9 97.5 85.4 Income tax receivable 12 16.7 16.6 TOTAL CURRENT ASSETS 1,201.1 961.7 TOTAL ASSETS 7,582.8 7,684.7 Share capital 1,977.2 1,977.2 Hedging reserve 12 299.1 118.8 Foreign currency translation (368.1) (107.0) Retained earnings/(deficit) (56.5) (103.5) TOTAL EQUITY 1,851.7 1,885.5 NON-CURRENT LIABILITIES Provisions 11 1,571.2 1,654.2 Long-term borrowings 12 1,863.3 1,815.6 Derivative instruments 12 10.5 28.6 Income tax payable 63.3 59.0 Other non-current liabilities 10 128.3 164.6 Deferred tax liabilities 734.7 750.1 TOTAL NON-CURRENT LIABILITIES 4,371.3 4,472.1 CURRENT LIABILITIES Provisions 11 86.5 113.5 Short-term borrowings 12 66.3 124.0 Derivative instruments 12 32.3 18.6 Trade and other payables 10 229.7 222.7 Income tax payable 118.3 155.3 Other current liabilities 10 826.7 693.0 TOTAL CURRENT LIABILITIES 1,359.8 1,327.1 TOTAL EQUITY AND LIABILITIES 7,582.8 7,684.7

Neptune Energy Group Midco Limited Unaudited Condensed Consolidated Financial Statements For the three months ended 31 March 2020

Neptune Energy Group Midco Limited Report for the period ended 31 March 2020 20

Unaudited Condensed Consolidated Statement of Changes in Equity

Group In millions of US$ Share Capital Hedging reserve Foreign currency translation Retained earnings Total As at 1 January 2020 1,977.2 118.8 (107.0) (103.5) 1,885.5 Profit for the period

• 47.0

47.0 Other comprehensive income

• 180.3

(261.1)

• (80.8)

Total comprehensive income

• 180.3

(261.1) 47.0 (33.8) As at 31 March 2020 1,977.2 299.1 (368.1) (56.5) 1,851.7 Group In millions of US$ Share Capital Hedging reserve Foreign currency translation Retained earnings Total As at 1 January 2019 1,977.2 (25.1) (142.8) (122.4) 1,686.9 Profit for the year

• 52.7

52.7 Other comprehensive income

• 37.4

53.5

• 90.9

Total comprehensive income

• 37.4

53.5 52.7 143.6 As at 31 March 2019 1,977.2 12.3 (89.3) (69.7) 1,830.5

1) The hedging reserve represents gains and losses on derivatives classified as effective cash flow hedges. 2) The foreign currency translation reserve represents exchange gains and losses arising on translation of foreign currency subsidiaries.

Neptune Energy Group Midco Limited Unaudited Condensed Consolidated Financial Statements For the three months ended 31 March 2020

Neptune Energy Group Midco Limited Report for the period ended 31 March 2020 21

Unaudited Condensed Consolidated Cash Flow Statement

Group In millions of US$ Three months ended 31 March 2020 Three months ended 31 March 2019 Cash Flows from Operating Activities Profit before taxation 118.4 206.6 Adjustments to reconcile profit before tax to net cash flows: Depreciation and amortisation 147.5 170.2 Unsuccessful exploration costs written off 11.5 0.6 Finance costs 49.2 66.3 Finance income (12.3) (1.5) Share of net income from equity investments (9.4) (0.6) Other non-cash income and expenses (3.7) 16.9 Fair value movement on commodity based derivative instruments 11.0 (14.6) Movement in provisions including decommissioning expenditure (22.4) (15.1) Working capital adjustments 102.7 4.1 Income tax paid (net) (37.3) (70.6) Net cash flows used in operating activities 355.2 362.3 Cash Flows from Investing Activities Expenditure on exploration and evaluation assets (39.1) (3.1) Expenditure on property, plant and equipment (232.8) (152.7) Proceeds from sale of equity investments

• 7.7

Proceeds from sale of assets 0.7

• Finance income received

2.2 1.5 Net investment made in equity accounted investments (12.5) (15.1) Net cash flows used in investing activities (281.5) (161.7) Cash Flows from Financing Activities Proceeds from loans and borrowings 495.5 41.0 Repayment of borrowings (514.5) (229.0) Repayment of obligations under leases (17.0) (3.3) Finance costs paid (24.5) (35.0) Net cash flows from financing activities (60.5) (226.3) Net increase/(decrease) in cash and cash equivalents 13.2 (25.7) Cash and cash equivalents at 1 January 85.4 197.3 Net foreign exchange differences (1.1) (0.4) Cash and cash equivalents at 31 March 97.5 171.2

Neptune Energy Group Midco Limited Unaudited Condensed Consolidated Financial Statements For the three months ended 31 March 2020

Neptune Energy Group Midco Limited Report for the period ended 31 March 2020 22

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 condensed consolidated financial statements of Neptune Energy Group Midco Limited and its subsidiaries (collectively, the Group) for the three months ended 31 March 2020 were authorised for issue in accordance with a resolution of the Board on XX May 2020. The Group is principally engaged in oil and gas exploration and production. The information for the period ended 31 December 2019 contained within the condensed financial statements does not constitute statutory accounts within the meaning of section 434 of the Companies Act 2006. Statutory accounts for the period ended 31 December 2019 were approved by the Board of Directors on 30 March 2020 and delivered to the Registrar of Companies. Those accounts contained an unqualified auditors’ report which included an emphasis of matter concerning the effects of COVID-19 and did not contain any statement under section 498(2) or 498(3) of the Companies Act 2006. 1. Basis of preparation The condensed consolidated financial statements for the three months ended 31 March 2020 have been prepared in accordance with IAS 34 Interim Financial Reporting. The condensed consolidated financial statements do not include all the information and disclosures required in the annual financial statements and should be read in conjunction with the Group’s consolidated financial statements as at 31 December 2019 which contains additional accounting policy disclosure. The preparation of financial statements in conformity with IAS 34 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 the 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 2019 except where, due to the adoption of new standards effective as of 1 January 2020 (see note 1.1). 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 Group Interest Rate Benchmark Reform (effective 1 January 2020) Interest rate benchmark reform amendments to IFRS 9, IAS39 and IFRS 7, was issued by the IASB in September 2019. Interbank

• ffered rates (IBORs) are interest reference rates, such as LIBOR, EURIBOR and TIBOR, that represent the cost of obtaining

unsecured funding, in a particular combination of currency and maturity and in a particular interbank term lending market. Reforms are underway which aim to achieve a shift away from individual trader quotes to observed transaction rates and to increase the population on which those rates are based. The International Accounting Standards Board (IASB) has published 'Interest Rate Benchmark Reform (Amendments to IFRS 9, IAS 39 and IFRS 7)' as a first reaction to the potential effects the IBOR reform could have on financial reporting. The amendments are effective for annual periods beginning on or after 1 January 2020, with earlier application permitted. The guidance published considers reliefs to hedge accounting in the period before the reform. These amendments provide temporary relief from applying specific hedge accounting requirements to hedging relationships directly affected by IBOR

• reform. The reliefs have the effect that IBOR reform should not generally cause hedge accounting to terminate. However, any

hedge ineffectiveness should continue to be recorded in the income statement under both IAS 39 and IFRS 9. Furthermore, the amendments set out triggers for when the reliefs will end. As the majority of the hedging instruments held by the Group are commodity based they are not impacted by the proposed

• amendments. Those few hedging instruments that the Group holds which might otherwise be effected by the proposed

amendment are all expected to mature before any reform to the interest rate benchmark has been finalised and so the new amendment is expected to have no impact on the current financial statements of the Group

Neptune Energy Group Midco Limited Unaudited Condensed Consolidated Financial Statements For the three months ended 31 March 2020

Neptune Energy Group Midco Limited Report for the period ended 31 March 2020 23

Several other financial reporting amendments and interpretations apply for the first time in 2020, but do not have an impact

• n the interim condensed consolidated financial statements of the Group.

1.2 Measurement and presentation basis The condensed consolidated financial statements have been prepared using the historical cost convention, except for financial instruments that are accounted for according to the financial instrument categories defined by IFRS 9. The consolidated financial statements are presented in US dollars and rounded to millions, except when otherwise indicated. 1.3 Significant judgements and estimates Estimates 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 Estimates The preparation of condensed 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. 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, pensions and post-employment obligations;  measurement of recognised tax loss carry-forwards; and  assessment 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 goodwill The 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. Where relevant these estimates are based on life of field projections and generally only include sanctioned fields and projects. 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. 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

• n 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 2018) 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 8 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.

Neptune Energy Group Midco Limited Unaudited Condensed Consolidated Financial Statements For the three months ended 31 March 2020

Neptune Energy Group Midco Limited Report for the period ended 31 March 2020 24

Estimates of decommissioning provisions Parameters 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 11 for further information. Pensions and post–employment benefit obligations Defined benefit pension 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. Pension costs for interim periods are calculated on the basis of the actuarial valuations performed at the end of the prior year. If necessary, these valuations are adjusted to take account of curtailments, settlements or other major non-recurring events that have occurred during the period. Measurement of recognised tax loss carry-forwards Deferred 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 estimated future taxable profits. These estimates are based on life of field projections and generally

• nly include sanctioned fields and projects. Unsanctioned wells and fields may be included if future profits are considered to

be probable in the relevant circumstances. The estimates use underlying assumptions on prices, capital and operating expenditure and reserves which are consistent with those used for asset impairment review. 1.3.2 Judgements As well as relying on estimates, the Directors make judgments 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

• r 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 for 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

• utlined 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.

Neptune Energy Group Midco Limited Unaudited Condensed Consolidated Financial Statements For the three months ended 31 March 2020

Neptune Energy Group Midco Limited Report for the period ended 31 March 2020 25

2. Financial risk management Group financial risk factors The 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. Please refer to our Risk disclosure in the Neptune Energy 2019 Annual Report and Accounts.

Neptune Energy Group Midco Limited Unaudited Condensed Consolidated Financial Statements For the three months ended 31 March 2020

Neptune Energy Group Midco Limited Report for the period ended 31 March 2020 26

3. Segmental information Revenue from contracts with customers 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 two geographical regions comprising seven areas: UK, Norway, Netherlands, Germany, North Africa, Asia Pacific and Corporate.

Three months ended 31 March 2020 Group In millions of US$ UK Norway Netherlands Germany North Africa Asia Pacific Corporate 2020 Total Production revenue by origin 53.7 217.1 56.1 42.6 11.3 89.4

• 470.2

Other revenue 1.5 0.4 5.8 1.8

• 9.5

Revenue 55.2 217.5 61.9 44.4 11.3 89.4

• 479.7

Current Operating Income 15.0 89.1 17.8 (4.3) 1.7 34.4 (0.6) 153.1 Share of net income from investments using equity method

• 0.2
• 9.2
• 9.4

Net Operating Profit After Equity Accounted Investments 15.0 89.1 18.0 (4.3) 10.9 34.4 (0.6) 162.5 Other operating (losses)/ gains (7.2) Profit Before Financial Items 155.3 Financial income 12.3 Finance costs (49.2) Profit Before Tax 118.4 Three months ended 31 March 2019 Group In millions of US$ UK Norway Netherlands Germany North Africa Asia Pacific Corporate 2019 Total Production revenue by origin 55.4 285.7 91.8 53.6 12.1 116.5

• 615.1

Other revenue 1.4

• 3.9

0.7

• 6.0

Revenue 56.8 285.7 95.7 54.3 12.1 116.5

• 621.1

Current Operating Income 25.7 179.0 37.3 7.9 (3.3) 43.1 (16.7) 273.0 Share of net income from investments using equity method

• 0.3
• 0.3
• 0.6

Net Operating Profit After Equity Accounted Investments 25.7 179.0 37.6 7.9 (3.0) 43.1 (16.7) 273.6 Other operating (losses)/ gains (2.3) Profit Before Financial Items 271.3 Financial income 1.7 Finance costs (66.4) Profit Before Tax 206.6 Three months ended 31 March 2020 Group In millions of US$ UK Norway Netherlands Germany North Africa Asia Pacific Corporate Total EBITDAX (including equity accounted affiliates) 38.9 144.1 36.2 13.3 14.8 84.7 0.1 332.1 Three months ended 31 March 2019 Group In millions of US$ UK Norway Netherlands Germany North Africa Asia Pacific Corporate Total EBITDAX (including equity accounted affiliates) 46.7 229.7 68.8 21.5 0.7 100.0 (16.1) 451.3

Neptune Energy Group Midco Limited Unaudited Condensed Consolidated Financial Statements For the three months ended 31 March 2020

Neptune Energy Group Midco Limited Report for the period ended 31 March 2020 27 31 March 2020 Group In millions of US$ UK Norway Netherlands Germany North Africa Asia Pacific Corporate Total Balance Sheet Assets 1,451.5 2,441.4 774.0 549.8 725.3 1,533.5 107.3 7,582.8 Liabilities (280.9) (1,574.8) (903.5) (602.7) (22.1) (318.9) (2,028.2) (5,731.1) Net Assets 1,170.6 866.6 (129.5) (52.9) 703.2 1,214.6 (1,920.9) 1,851.7

4. Other operating losses/(gains)

Group In millions of US$ Three months ended 31 March 2020 Three months ended 31 March 2019 Mark-to-market on currency and commodity contracts 11.0 (14.6) Restructuring provision cost/(release) (0.3) 17.8 Other gains (3.5) (0.9) Total 7.2 2.3

5. Taxation

The Group calculates the period income tax expense using the tax rate that would be applicable to the expected total annual earnings. The major components of income tax expense in the condensed statement of profit or loss are:

Group In millions of US$ Three months ended 31 March 2020 Three months ended 31 March 2019 Current taxation 24.0 140.5 Deferred taxation 47.4 13.4 Total Income tax expense recognised in income statement 71.4 153.9

The effective tax rate for the Group for 2020 was 60% (2019: 74%).

• 6. Goodwill

Group In millions of US$ 31 March 2020 Cost as at 1 January 640.8 Currency translation adjustments (91.7) Cost as at 31 March 549.1

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 assigned to Norway is $460.4 million. The remaining goodwill is assigned to the Netherlands, Germany and Egypt group of CGUs. The goodwill from these business combinations is reviewed for impairment prospectively at each reporting date, or earlier if there are indications of impairment. Further information on the review for impairment is available in the Neptune Energy Group 2019 Annual Report and Accounts in note 12.

Neptune Energy Group Midco Limited Unaudited Condensed Consolidated Financial Statements For the three months ended 31 March 2020

Neptune Energy Group Midco Limited Report for the period ended 31 March 2020 28

7. Intangible assets

Group In millions of US$ Exploration and evaluation Other Total Cost at 1 January 2020 138.6 28.6 167.2 Additions 39.1 0.2 39.3 Unsuccessful exploration expenditure (11.5)

• (11.5)

Transfers to property, plant and equipment (1.4)

• (1.4)

Currency translation adjustments (8.5) (2.7) (11.2) Cost at 31 March 2020 156.3 26.1 182.4 Amortisation at 1 January 2020

• (16.3)

(16.3) Charge for the year

• (1.0)

(1.0) Currency translation adjustments

• 1.0

1.0 Amortisation at 31 March 2020

• (16.3)

(16.3) Net book value at 31 March 2020 156.3 9.8 166.1 Net book value at 31 December 2019 138.6 12.3 150.9

Unsuccessful exploration expenditure relates to costs associated with an uncommercial well evaluation. 8. Property, plant and equipment

Group In millions of US$ Oil and gas properties Other fixed assets Total Cost at 1 January 2020 5,627.3 85.8 5,713.1 Additions 241.2 (1.3) 239.9 Disposals (2.8)

• (2.8)

Transfers from intangible assets 1.4

• 1.4

Currency translation adjustments (427.7) (4.3) (432.0) Cost at 31 March 2020 5,439.4 80.2 5,519.6 Accumulated depreciation at 1 January 2020 (1,268.4) (13.9) (1,282.3) Charge for year (147.4) (3.0) (150.4) Disposals 2.8

• 2.8

Currency translation adjustments 82.1 0.9 83.0 Accumulated depreciation at 31 March 2020 (1,330.9) (16.0) (1,346.9) Net book value at 31 March 2020 4,108.5 64.2 4,172.7 Net book value at 31 December 2019 4,358.9 71.9 4,430.8

1) Includes capitalised depreciation of $3.9 million related to right-of-use assets in Norway.

Neptune Energy Group Midco Limited Unaudited Condensed Consolidated Financial Statements For the three months ended 31 March 2020

Neptune Energy Group Midco Limited Report for the period ended 31 March 2020 29

9. Cash and cash equivalents

Group In millions of US$ 31 March 2020 31 December 2019 Cash at bank and in hand 87.2 75.1 Restricted cash 10.3 10.3 Total cash and cash equivalents 97.5 85.4

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.

• 10. Trade payables and other liabilities

Group In millions of US$ 31 March 2020 31 December 2019 Trade and other payables 229.7 222.7 Other current liabilities 715.9 567.5 Lease liabilities 63.8 72.3 Wages and social security 47.0 53.2 Current trade payables and accruals 1,056.4 915.7 Other non-current liabilities 54.2 64.9 Lease liabilities 74.1 99.7 Non-Current trade payables and accruals 128.3 164.6 Total 1,184.7 1,080.3

Trade payables are usually paid within 30 days of recognition. The carrying amount of financial assets and financial liabilities approximates their fair value and they are all due within one year. Included within other current liabilities is $200.0 million (2019: $200.0 million) in respect of a promissory note issued on 11 December 2019 to the immediate and ultimate parent undertaking in respect of the interim dividend declared and Indonesian deferred income of $67.5 million (2019: $67.5 million). The remainder of the balance is principally related to joint venture funding.

• 11. Provisions

Group In millions of US$ 31 March 2020 31 December 2019 Current Restructuring 25.8 41.8 Post-employment benefit and other long term benefits 10.2 11.4 Decommissioning 45.4 55.0 Other 5.1 5.3 Current Total 86.5 113.5 Non-Current Restructuring 29.9 24.8 Post-employment benefit and other long term benefits 176.9 183.6 Decommissioning 1,364.4 1,445.8 Non-Current Total 1,571.2 1,654.2 Total 1,657.7 1,767.7

Neptune Energy Group Midco Limited Unaudited Condensed Consolidated Financial Statements For the three months ended 31 March 2020

Neptune Energy Group Midco Limited Report for the period ended 31 March 2020 30

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. Further information on decommissioning provisions is available in the Neptune Energy Group 2019 Annual Report and Accounts in note 22.

• 12. Financial assets and financial liabilities

Set out below is an overview of financial assets and liabilities, other than cash and short-term deposits, held by the Group as at 31 March 2020 and 31 December 2019.

Group In millions of US$ 31 March 2020 31 December 2019 Financial assets at fair values Commodity derivatives at fair value through profit and loss 1.4 1.5 Commodity derivatives in qualifying hedging relationships 433.9 220.7 Foreign forward exchange contracts at fair value through profit and loss 0.4 0.1 Equity instruments designated at fair value through OCI 10.58% interest in Erdgas-Verkaufs-Gesellschaft mbH, Münster 18.8 19.3 Financial assets at Amortised Cost Trade and other receivables 711.9 651.9 Income Tax receivable 16.7 16.6 Other non-current assets 98.2 110.6 Total 1,281.3 1,020.7 Total current 1,043.9 815.9 Total Non-current 237.4 204.8

Fair value is the amount at which a financial instrument could be exchanged in an arm's length transaction, other than in a forced or liquidated sale. Where available, market values have been used to determine fair values. The estimated fair values have been determined using market information and appropriate valuation methodologies. Values recorded are as at the balance sheet date and will not necessarily be realised. Non-interest bearing financial instruments, which include amounts receivable from customers and accounts payable are also recorded materially at fair value reflecting their short-term maturity. The Fair values of all derivative financial instruments are based on estimates from observable inputs and are all level 2 in the IFRS 13 hierarchy. The valuation of Neptune’s interest in Erdgas Münster its sole equity investment, has been calculated based on an enterprise value/EBITDA multiple taking into account recent transactions involving suitable comparative infrastructure companies, which are based on unobservable inputs and are level 3 in the IFRS 13 hierarchy.

Neptune Energy Group Midco Limited Unaudited Condensed Consolidated Financial Statements For the three months ended 31 March 2020

Neptune Energy Group Midco Limited Report for the period ended 31 March 2020 31 Group In millions of US$ 31 March 2020 31 December 2019 Financial liabilities at Fair Value Commodity derivatives in qualifying hedging relationships 15.6 39.5 Interest rate derivatives in qualifying hedging relationships 10.4 5.6 Foreign forward exchange contracts at fair value through profit and loss 16.8 2.1 Contingent consideration of the VNG Norge AS acquisition 19.6 23.2 Financial liabilities at amortised cost Reserve base lending facility 706.7 643.7 Senior Notes 832.7 831.8 Touat project finance facility 261.3 256.2 DNB uncommitted facility 21.0 50.0 Citi Bank uncommitted facility

• 50.0

Subordinated Neptune Energy Group Limited loan 107.9 107.9 Trade and other payables 229.7 222.7 Wages and social security 47.0 53.2 Lease liabilities 137.9 172.0 Corporate taxes payable 181.6 214.3 Other liabilities 750.5 609.2 Total 3,338.7 3,281.4 Total current 1,273.3 1,213.6 Total Non-current 2,065.4 2,067.8

Set out above is an overview of financial liabilities, other than cash and short-term deposits, held by the Group as at 31 March

• 2020. The Senior Notes held by the Group have a fair value of $475.1 million, compared to the carrying amount of $832.7

million (31 December 2019: a fair value of $850.4 million, compared with the carrying amount of $831.8 million) reflecting the current volatility in the market environment. This financial liability is 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. The valuation of contingent consideration relates to the Company’s acquisition of VNG and is based on management’s view of the most likely future liability that will be settled which are based on unobservable inputs and are level 3 in the IFRS 13 hierarchy. 12.1 Financial assets and financial liabilities – hierarchy Set out below is an overview of the hierarchy of financial assets and financial liabilities, other than cash and short- term deposits, held by the Group as at 31 March 2020 and 31 December 2019. For items held at amortised cost, there is no significant difference between their fair value and amortised cost value. There have been no transfers between fair value levels during the period for either assets or liabilities

31 March 2020 In millions of US$ Date of valuation Total Significant

• bservable

inputs (Level 2) Significant unobservable inputs (Level 3) Assets measured at fair value Derivative financial assets Commodity derivatives in qualifying hedging relationships 31-Mar-20 433.9 433.9

• Commodity derivatives at fair value through profit and loss

31-Mar-20 1.4 1.4

• Foreign forward exchange contracts at fair value through profit and loss

31-Mar-20 0.4 0.4

• Non-Listed equity Instruments

10.58% interest in Erdgas Münster GMBH 31-Mar-20 18.8

• 18.8

Total 454.5 435.7 18.8

Neptune Energy Group Midco Limited Unaudited Condensed Consolidated Financial Statements For the three months ended 31 March 2020

Neptune Energy Group Midco Limited Report for the period ended 31 March 2020 32 31 December 2019 Group In millions of US$ Date of valuation Total Significant

• bservable

inputs (Level 2) Significant unobservable inputs (Level 3) Assets measured at fair value Derivative financial assets Commodity derivatives in qualifying hedging relationships 31-Dec-19 220.7 220.7

• Commodity derivatives at fair value through profit and loss

31-Dec-19 1.5 1.5

• Foreign forward exchange contracts at fair value through profit and loss

31-Dec-19 0.1 0.1

• Non-listed equity Instruments

10.58% interest in Erdgas Münster GMBH 31-Dec-19 19.3

• 19.3

Total 241.6 222.3 19.3 31 March 2020 Group In millions of US$ Date of valuation Total Significant

• bservable

inputs (Level 2) Significant unobservable inputs (Level 3) Liabilities measured at fair value Derivatives financial liabilities Commodity derivatives in qualifying hedging relationships 31-Mar-20 15.6 15.6

• Commodity derivatives at fair value through profit and loss

31-Mar-20

• Interest rate derivatives in qualifying hedging relationships

31-Mar-20 10.4 10.4

• Forward Foreign exchange contracts at fair value through profit and loss

31-Mar-20 16.8 16.8

• Contingent consideration

19.6

• 19.6

Total 62.4 42.8 19.6 31 December 2019 Group In millions of US$ Date of valuation Total Significant

• bservable

inputs (Level 2) Significant unobservable inputs (Level 3) Liabilities measured at Fair Value Derivative financial liabilities Commodity derivatives in qualifying hedging relationships 31-Dec-19 39.5 39.5

• Interest rate derivatives in qualifying hedging relationships

31-Dec-19 5.6 5.6

• Forward foreign exchange contracts at fair value through profit and loss

31-Dec-19 2.1 2.1

• Contingent consideration of the VNG Norge AS acquisition

31-Dec-19 23.2

• 23.2

Total 70.4 47.2 23.2

12.2 Change in the value of Level 3 Instruments

The following table presents the changes in Level 3 instruments for the 3 months ended 31 March 2020.

Group In millions of US$ Equity Investments Contingent Consideration Total Fair value at 1 January 19.3 (23.2) (3.9) (Losses)/gains recognised in the income statement*

• 3.6

3.6 (Losses)/gains recognised in other comprehensive income (0.5)

• (0.5)

Fair value at 31 March 2020 18.8 (19.6) (0.8)

* Includes unrealised gains or (losses) recognised in profit or loss attributable to balances held at the end of the reporting period.

A 5 per cent change in the EBITDA multiple to the Level 3 instrument above as applied would result in a $0.9 million change in valuation (Dec 2019 1.0m).

Neptune Energy Group Midco Limited Unaudited Condensed Consolidated Financial Statements For the three months ended 31 March 2020

Neptune Energy Group Midco Limited Report for the period ended 31 March 2020 33

12.3 Hedging reserve The 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.

Group In millions of US$ Cash flow commodity 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 2020 (123.7) (0.7) 5.6

• (118.8)

Add costs of hedging deferred and recognised in OCI (343.5) 43.3 5.8

• (294.4)

Less reclassified from OCI to profit or loss or included in finance costs 59.0 (3.2) (1.0)

• 54.8

Less deferred tax 92.0 (32.7)

• 59.3

At 31 March 2020 (316.2) 6.7 10.4

• (299.1)

The Company has identified the following potential sources of hedge ineffectiveness in its hedging relationships:  CVA/DVA mismatches between the hedging instrument and the hedged item  the effects from discounting arising from settlement date mismatches between the hedging instrument and hedged item  the effects from the unwind of discounting from the designation of certain off-market hedging instruments in hedging relationships.

• 13. Share capital

Number US$ million Allotted, called up and fully paid At 31 December 2019 and 31 March 2020 1,977,175,201 1,977.2

• 14. Contingent liabilities

During the normal course of its business, the Group may be involved in disputes, including tax disputes. Where applicable 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. There have been no changes in the period since the 2019 year end disclosure. Further details on contingencies can be found in Note 26 of the Neptune Energy Group 2019 Annual Report and Accounts.

• 15. Related party transactions

There were no material related party transactions in the three months ended 31 March 2020 nor in the three months ended 31 March 2019.

• 16. Events after the reporting period

Post the balance sheet date, macro-economic uncertainty has continued due to the COVID-19 pandemic, which has impacted

• il and gas pricing in addition to significant commodity market volatility relating to the global supply of oil. This volatility may

have an impact on our earnings and cash flow but we are a resilient business, with an effective hedging and overall risk management programme in place. We have established mitigation plans for our projects and will continue to evaluate supply chains for ongoing impacts. On 15 April 2020, Neptune Energy amended its $2.0 billion RBL credit facility with its bank syndicate. Principal changes include, the addition of the Merakes, Indonesia and Touat, Algeria assets to the borrowing base. As a result of these changes, the new borrowing base has increased from $2.0 billion to $2.3 billion for the next 12 months. In addition, the first scheduled amortisation was delayed from 2021 to 2022, while the final facility maturity date remained unchanged in May 2024. We have also exercised the accordion option to upsize the RBL credit facility from $2.0 billion to $2.6 billion.

Neptune Energy Group Midco Limited Unaudited Condensed Consolidated Financial Statements For the three months ended 31 March 2020

Neptune Energy Group Midco Limited Report for the period ended 31 March 2020 34

On 19 May 2020, Neptune Energy announced that it has agreed to terminate the agreement to acquire Edison E&P’s UK and Norwegian subsidiaries from Energean Oil and Gas. Neptune will pay a $5 million termination fee to Energean.