NEPTUNE ENERGY 2019 3 rd QUARTER RESULTS Neptune Energy Group Midco - - PDF document

NEPTUNE ENERGY 2019 3rd QUARTER RESULTS

Neptune Energy Group Midco Limited Unaudited Condensed Consolidated Financial Statements For the nine months ended 30 September 2019

Neptune Energy Group Midco Limited Report for the nine months ended 30 September 2019 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. This report includes the results of the acquired EPI business consolidated since 15 February 2018, which is the acquisition date as that is when Neptune acquired control over EPI. Comparative data for Neptune for the corresponding reporting period ended 30 September 2019 therefore includes only seven and a half months results contribution from the EPI business. 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 other things, assumptions with respect to production, future capital expenditures and cash flow, we caution you that the assumptions used in the preparation

• f 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

• r 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.

Neptune Energy Group Midco Limited Report for the period ended 30 September 2019 3

NEPTUNE ENERGY ANNOUNCES 3rd QUARTER 2019 RESULTS London, 22 November 2019 – Neptune Energy, the global independent oil and gas exploration and production company, today announces its financial results for the period ended 30 September 2019. Continued strategic progress focused on value-accretive growth, increasing long-life and low-cost reserves in key areas  Announced agreement to acquire Edison E&P’s UK and Norwegian producing, development and exploration assets from Energean Oil & Gas: portfolio provides further growth with 30 mmboe of 2P reserves, 15 kboepd of near-term production and additional contingent resources.  Important discovery at Echino South in Norway: discovery located close to existing infrastructure, with an estimated 38-100 mmboe of recoverable resources. Potential for fast-track development.  Officially signed West Ganal PSC: covers an area of 1,129 km2 and is located adjacent to our existing Jangkrik and Jangkrik NE fields in the prolific Kutei Basin, Indonesia. Includes the Maha discovery, which has 24 mmboe of 2C resources. Production expected to increase with new projects set to contribute ~110 kboepd in coming years  Production expected to increase in the fourth quarter: the Touat gas development, in Algeria, is ramping up to plateau, while production in Norway and the Netherlands is expected to return to normal levels.  More than 110 kboepd of new production under development: projects remain on track and on budget. Merakes (Indonesia) and Nova and Dvalin (Norway) added to development pipeline from recent acquisitions.  Full year 2019 average production guidance of around 145 kboepd: revised guidance reflects later than expected start-up and plateau at Touat, maintenance shutdowns and other unplanned deferrals. Strong balance sheet, disciplined capital allocation and healthy liquidity levels  Expect robust full year cash flow, despite modest commodity prices and lower production: expect to deliver operating cash flow of more than $1 billion in 2019, reflecting disciplined capital allocation and a low cost base of around $10.5/boe.  Liquidity boosted by $300 million bond issue: additional issuance to the existing $550 million Senior Notes due 2025. Total headroom of $1.7 billion, including $1.5 billion currently available and undrawn under the RBL facility.  Higher capital investment programme for 2020, funded from existing resources: proposed development capex programme of approximately $1-1.1 billion in 2020, before falling to around current levels in 2021 as new projects come on stream. FINANCIAL SUMMARY

Neptune Energy Q3 2019 Q2 2019 Q1 2019 Q1-Q3 2019 Q1-Q3 2018 (note a) 3 months to 30 Sept 2019 3 months to 30 June 2019 3 months to 31 March 2019 9 months to 30 Sept 2019 15 Feb – 30 Sept 2018 Total daily production (kboepd) (note c) 130.8 145.6 151.8 142.6 160.5 Average realised oil price ($/bbl)(note b,c) 64.2 65.9 58.5 62.1 70.7 Average realised gas price ($/mcf)(note b,c) 3.6 4.4 6.5 5.0 7.8 EBITDAX ($m) (note d) 331.4 430.8 451.0 1,213.2 1,330.6 Operating costs ($/boe) 11.2 10.8 10.1 10.6 11.2 Operating cash flow ($m) 334.2 250.7 362.3 947.2 822.5

a) Results for 2018 reflect the acquired EPI business from 15 February to 30 September 2018. The unaudited results for the period ended 30 September 2018 as previously disclosed have been revised as they were based on provisional assigned fair values of the acquisition of the EPI business on 15 February 2018. b) Average realised prices are stated before 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.

Neptune Energy Group Midco Limited Report for the period ended 30 September 2019 4

Jim House, Chief Executive Officer “Neptune made significant strategic progress in the third quarter, focused on delivering value-accretive and material growth, increasing long-life and low-cost reserves in key areas of our portfolio. Our acquisition of Edison E&P’s North Sea assets from Energean Oil & Gas is an excellent fit with our existing portfolio in Norway and the UK and offer additional contingent resources, while the discovery at Echino South in Norway is one of the year’s largest on the Norwegian continental shelf and has the potential for fast- track development. “We have a strong project pipeline, which will deliver 110 kboepd of new production in the coming years. We expect to exit 2019 producing at higher levels as Touat continues to ramp up to plateau and production in Norway and the Netherlands returns to more normal levels.” GROUP OVERVIEW Neptune Energy continued to make good strategic progress through our agreement with Energean Oil & Gas to acquire Edison E&P’s UK and Norwegian producing, development and exploration assets. The transaction offers us material growth in contingent resources, 2P reserves and near-term production and is in line with our strategy of consolidating our position in key areas with high quality and complementary assets, preferably through value accretive ‘bolt-on’ acquisitions. The assets are a good fit with our existing North Sea portfolio, with Nova and Dvalin expected to add 12 kboepd over the next two years and Glengorm adding significant upside potential for the longer term. In early November, Equinor announced an important discovery at our Echino South exploration well. The new discovery, which is one

• f the largest made on the Norwegian Continental Shelf in 2019, has recoverable resources estimated at 38-100 mmboe. Located

close to the Fram field, Echino South has the potential for a fast-track development through existing infrastructure. In October, we officially signed the West Ganal PSC, which we announced in August. The signing follows our agreement with ENI to acquire interests in the East Sepinggan and East Ganal PSCs, both in the strategically important Kutei Basin in Indonesia. The acquisitions provide access to significant net reserves and resources in addition to exposure to multi Tcf exploration potential across the basin. In the East Sepinggan PSC, development of the Merakes field is underway as a tie-back into our Jangkrik Floating Production Unit (FPU). Together, these transactions are complementary to our large-scale and geographically diversified portfolio and provide us with long- life, low-cost production. We continue to make progress with health, safety, security and the environment (HSSE). HSSE remains our highest priority and we maintained our encouraging performance, with our key metrics, Lost Time Injury Frequency rate (LTIF) and Total Recordable Incident Rate (TRIR) further improving in the third quarter. We have maintained our focus on occupational and process safety, and delivered an improved method of risk management across the portfolio. We are also making good progress in developing our environmental strategy. We are committed to a production profile that is weighted more towards gas than oil due to its vital role in the transition to a lower carbon energy mix and stronger demand growth

• fundamentals. We have one of the lowest CO2 emissions intensities in the sector, and are implementing a new environmental policy,

which details our commitment to reduce emissions, improve energy efficiency and achieve a long-term intensity measure. We will set out our ESG strategy and provide more disclosure in these areas in our 2019 Annual Report & Accounts. Operationally, the third quarter of 2019 was challenging, with curtailments as a result of offtake restrictions at Gjøa and Gudrun in Norway, pipeline capacity constraints at Cygnus in the UK, extended maintenance in the Netherlands and periodic offtake restrictions amounting to a 15 per cent curtailment against plan in Indonesia. As a result, production fell to 131 kboepd in the period. While first export gas from Touat, in Algeria, served to offset the fall marginally, the ramp up to plateau has taken longer than expected as we fine tune operational parameters at the recently commissioned plant. With production in Norway and the Netherlands returning to normal and Touat continuing to ramp up to plateau, we expect higher levels of production in the fourth quarter. However, lower production in the third quarter has resulted in us revising our full year average production guidance to around 145 kboepd, largely caused by the delayed ramp up of Touat.

Neptune Energy Group Midco Limited Report for the period ended 30 September 2019 5

While operating costs for the third quarter were $11.2/boe, reflecting lower production in the quarter, we expect them to be within

• ur original guidance range for the full year. Our cost efficiency programmes remain on track across the Group, with roles already

taken out in the Netherlands and Germany. We made good progress with our proposal to close our Paris office. In September, the consultation process with the French employee representatives was concluded and a collective agreement was signed with the unions on 1 October. We expect approval from the French labour administration in November. During the third quarter, our average realised commodity prices, excluding the impact of hedging, were $64.2/boe for oil and $3.6/mcf for gas, reflecting lower commodity prices during the period. Our active hedging programme continues to provide some protection from lower prices and we currently have hedges in place for 49 per cent of our crude oil sales and 65 per cent of our dry gas for the remainder of 2019. Lower production and weaker commodity prices resulted in operating cash flow of $334.2 million. However, we were still able to invest $278.7 million in our projects in the third quarter, largely in Norway at the Njord and Fenja projects. Net debt (excluding Subordinated Neptune Energy Group Limited loan and Touat Project Loan) at the end of the period was broadly unchanged at $1.1 billion, resulting in a net debt to EBITDAX (excluding our share of net income from Touat) ratio of 0.62 times. In October, we issued $300 million of additional Senior Notes due 2025, with the net proceeds used repay drawn commitments under

• ur Reserve Base Lending (RBL) facility. We currently have $1.5 billion of available undrawn facilities under the RBL, which combined

with our cash position of $159.2 million, provides headroom of $1.7 billion and fully funds our growth opportunities. Our strong pipeline of high quality development projects remain on track, with more than 110 kboepd coming into production in the next two years. This includes the Dvalin and Nova projects in Norway, which are due to come online from late next year and 2021, respectively. We continue to make good progress with our exploration programme, which includes the drilling of five wells in the second half of

• 2019. We began drilling the Schwegenheim prospect in Germany in September and expect preliminary results in the first quarter of
• 2020. The high impact Isabella well in the UK has also commenced, with results also expected in 2020. Drilling at Sigrun East appraisal

location will begin later in the year. In October, we announced that the global operations role would be split into two, with one role focusing on Europe and the other focusing on North Africa and Asia Pacific. Pete Jones, previously the Managing Director of Neptune’s UK business, has been appointed VP of Operations for Europe, while Philip Lafeber formally joins the executive management team in his current role as VP of Operations for North Africa and Asia Pacific. Splitting the role will provide even greater focus on these key areas during an important period of growth. Outlook With the ramp up of Touat underway and the return to normal production levels across Europe, we expect stronger production levels in the fourth quarter. However, lower than expected production in the third quarter, coupled with a slower ramp up at Touat, has resulted in us revising guidance for the full year to around 145 kboepd. For 2019, we expect full year opex to be around $10.5/boe, while development capex guidance remains broadly unchanged at around $750m, before the impact of M&A activities. In 2020, we expect average production to increase, reflecting a full year contribution from Touat and first production from Merakes and Dvalin. Guidance for 2020 will be provided at our full year results. Significant further production growth is expected in 2021 as we bring a number of key development projects onstream in Norway, the UK and Indonesia. To achieve this growth, we expect to increase investment on our development activities to around $1.0-1.1 billion in 2020, subject to final board approval. This programme is funded from existing resources, but will cause our Net Debt/EBITDAX leverage ratio to go above 1.5x on a temporary basis during 2020, until new projects are on stream, after which associated cash flows will be deployed for deleveraging. Maintaining cost and capital discipline will remain a key focus and we expect

• perating costs to be in the $10-11/boe range in 2020.

Neptune Energy Group Midco Limited Report for the period ended 30 September 2019 6

OPERATING REVIEW Health, safety, security and the environment Our HSSE performance was better than our targets for 2019 across all our countries in the third quarter of the year, resulting in an improvement of our LTIF and TRIR. There were no serious personal injuries and our LTIF rate improved to 0.46 per million hours worked, versus 0.59 when compared with the second quarter of 2019. Our TRIR improved to 1.99 per million hours worked versus 2.08 during the second quarter of 2019. These figures include cooperated joint venture activities. Our Process Safety Event Rate (PSER) KPI for the third quarter remained stable at 1.60 per million man hours, which is below our target of 5.0. Production

Neptune Energy Q3 2019 Q2 2019 Q1 2019 YTD 2019 2018 (note a) 3 months to 30 Sept 2019 3 months to 30 June 2019 3 months to 31 March 2019 9 months to 30 Sept 2019 15 Feb – 30 Sept 2018

Total production (mmboe) 11.9 13.2 13.7 38.8 36.6 Dry gas production (kboepd) 65.5 74.6 79.0 73.0 84.4 Gas production for sale as LNG (kboepd) 26.2 29.1 29.1 28.0 33.7 Liquid production (kbpd) 38.4 41.9 43.7 41.4 42.4 Total production (kboepd) 130.1 145.6 151.8 142.4 160.5

a) Results for this period consolidate the acquired EPI business for the post acquisition period, from 15 February 2018 to 30 September 2018.

Norway Production

Neptune Energy – Norway Q3 2019 Q2 2019 Q1 2019 YTD 2019 2018 (note a) 3 months to 30 Sept 2019 3 months to 30 June 2019 3 months to 31 March 2019 9 months to 30 Sept 2019 15 Feb – 30 Sept 2018

Gas production (kboepd) 20.4 26.2 26.9 24.5 29.0 Gas production for sale as LNG (kboepd) 13.5 13.5 12.5 13.1 13.7 Liquid production (kbpd) 29.4 32.8 32.8 31.7 31.7 Total production (kboepd) 63.3 72.5 72.2 69.3 74.4

a) Results for this period consolidate the acquired EPI business for the post acquisition period, from 15 February 2018 to 30 September 2018.

In Norway, production in the third quarter averaged 63.3 kboepd, reflecting the impacts of planned shutdowns and third party inflicted curtailments at both Gjøa and Gudrun. Despite these challenges, production for the first nine months of the year remains above expectations, reflecting strong underlying performance and high production efficiencies. At our operated Gjøa field, gas exports were initially restricted during August by an unplanned shutdown of the third party Ethylene Plant at Mossmorran, in Scotland. The situation has been successfully mitigated through alternative marketing arrangements, however, volumes are expected to remain below the fields export potential for the remainder of 2019. During August, the Gjøa platform shutdown for work on the Nova development was completed as planned, with deferred volumes to be re-delivered in-kind at Nova start-up. In September, blending issues related to production reductions from third party fields and other unplanned downtime impacted production from our non-operated Gudrun field, which was otherwise strong and has consistently produced above plan in 2019. Production at Gudrun has since returned to normal levels.

Neptune Energy Group Midco Limited Report for the period ended 30 September 2019 7

Elsewhere, the three new Fram wells are now all onstream, ahead of plan and cost, with initial production rates well above

• expectations. The Snøhvit Nord well has also been brought onstream.

Operating costs for the third quarter were $6.1/boe, demonstrating a continued improvement in lifting costs. Operating costs benefitted from currency movements, savings through the business improvement plan, lower environmental costs at Gjøa and reduced tariffs at Gudrun. Development and exploration As part of the Energean transaction, announced in October, we will acquire interests in the Dvalin (10 per cent working interest) and Nova (15 per cent working interest) developments, which together are expected to add approximately 23 mmboe of 2P reserves and 12 kboepd of production. The Dvalin gas field is being developed as a subsea tie-back to the Heidrun platform and is expected to contribute 5 kboepd net to Neptune when it comes onstream towards the end of 2020. During the third quarter the Dvalin processing module was lifted onto the Heidrun platform and a four well drilling campaign commenced. Nova is a subsea tie-back to our operated Gjøa field and we expect it to add 7 kboepd net from first production, which is planned for the fourth quarter of 2021. The subsea pipelines and umbilicals were successfully installed during the third quarter, requiring a shutdown of the Gjøa platform. The Nova module remains on schedule to be lifted in the second quarter of 2020. Among our existing projects, the new Fram Troll C Gas Module is close to completion and is expected to be operational in the first quarter of next year. The Njord Area, Askeladd, Fenja and Duva/Gjøa P1 projects all continue to progress on plan. In the fourth quarter we plan to commence drilling at Gudrun, Duva and Askaladd. In early November, we announced an important discovery at Echino South. The new discovery, which is one of the largest made on the Norwegian Continental Shelf in 2019, has recoverable resources estimated at 38-100 mmboe. The discovery, in which Neptune has a 15 per cent working interest, is located close to the Fram field and has the potential for a fast-track development through existing infrastructure. The Skumnisse prospect, in which Neptune had only a small 7.56 per cent working interest, was unsuccessful. Netherlands Production

Neptune Energy – Netherlands Q3 2019 Q2 2019 Q1 2019 YTD 2019 2018 (note a) 3 months to 30 Sept 2019 3 months to 30 June 2019 3 months to 31 March 2019 9 months to 30 Sept 2019 15 Feb – 30 Sept 2018

Gas production (kboepd) 17.1 19.2 23.0 19.7 27.0 Liquid production (kbpd) 1.0 1.0 2.7 1.6 2.6 Total production (kboepd) 18.1 20.2 25.7 21.3 29.6

a) Results for this period consolidate the acquired EPI business for the post acquisition period, from 15 February 2018 to 30 September 2018.

As reported in our first half results, production in the Netherlands has been negatively impacted by unplanned shutdowns of the L5a- D and Q13a-A platforms. While both platforms are back online, L5a-D had been producing at reduced levels due to the limited availability of blend gas and temporary flow constraints. Blend gas availability returned to normal in October and is not expected to be a recurring issue. The Q13a-A platform was shut down in early April due to a process system integrity issue at the third party P15 platform. Production recommenced in early August, however, a booster compressor failure on P15, following a planned shutdown of the platform, limited exports from Q13a-A in September. Our operations in the Netherlands were also impacted in the third quarter by a turbine failure on the F3-FB platform at the end of July and delayed completion of the E17a-A6 and L5a-D4 development wells. Production from the F3-FB platform recommenced at the end of September and the E17a-A6 well was brought onstream in mid-October.

Neptune Energy Group Midco Limited Report for the period ended 30 September 2019 8

Reflecting these issues, production in the third quarter averaged 18.1 kboepd, which was 2.1 kboepd lower than in the second

• quarter. Following the start-up of E17a-A6, production in the Netherlands has been around 24 kboepd and is expected to exceed 25

kboepd when L5a-D4 commences production towards the end of the year. Operating costs in the Netherlands were $16.7/boe in the third quarter, reflecting lower production in the period. Development To improve facility integrity and production efficiency, we have implemented an enhanced regional inspection and maintenance campaign in the Netherlands. In September, the platform on the non-operated D12-B Sillimanite field was installed and we began development drilling ahead of first gas, anticipated in February 2020. A number of other infill and exploration opportunities are being evaluated for potential inclusion in our 2020 work programme as we seek to extend our production profile in the Netherlands. UK Production

Neptune Energy – UK Q3 2019 Q2 2019 Q1 2019 YTD 2019 2018 (note a) 3 months to 30 Sept 2019 3 months to 30 June 2019 3 months to 31 March 2019 9 months to 30 Sept 2019 15 Feb – 30 Sept 2018

Gas production (kboepd) 14.7 16.4 16.3 15.8 18.1 Liquid production (kbpd) 0.3 0.4 0.4 0.4 0.5 Total production (kboepd) 15.0 16.8 16.7 16.2 18.6

a) Results for this period consolidate the acquired EPI business for the post acquisition period, from 15 February 2018 to 30 September 2018.

In the UK, production was 1.8 kboepd lower in the third quarter at 15.0 kboepd, largely reflecting a planned shutdown in August, along with pipeline capacity constraints and temporary blend gas shortages. The shutdown was successfully completed eight days ahead of schedule. We have secured blend gas contracts for the remainder of the year and continue to work towards a longer term solution. Opex in the third quarter was $8.8/boe, reflecting lower production in the period. Development and exploration As part of the Energean transaction, we will acquire a 25 per cent working interest in the much heralded Glengorm gas condensate discovery in the Central North Sea. Glengorm is located close to our operated Seagull project and is an additional contingent resource. Appraisal drilling is planned for 2020. We will also acquire a portfolio of assets in the UK adding approximately 3 kboepd of production. This includes interests in Scott (10 per cent), Telford (16 per cent), Tors (68 per cent), Wenlock (80 per cent) and Markham (3.1 per cent) fields. In October, we commenced drilling the Isabella prospect in the Central North Sea, with initial results expected during H1 2020. Our Seagull project continues to progress on plan and in September we contracted the Rowan Gorilla VI rig to drill four wells, commencing in the third quarter of 2020. Further contracts are expected to be awarded in the fourth quarter of this year.

Neptune Energy Group Midco Limited Report for the period ended 30 September 2019 9

Germany Production

Neptune Energy – Germany Q3 2019 Q2 2019 Q1 2019 YTD 2019 2018 (note a) 3 months to 30 Sept 2019 3 months to 30 June 2019 3 months to 31 March 2019 9 months to 30 Sept 2019 15 Feb – 30 Sept 2018

Gas production (kboepd) 6.7 6.9 7.3 7.0 7.2 Liquid production (kbpd) 5.7 5.6 5.5 5.6 5.8 Total production (kboepd) 12.4 12.5 12.8 12.6 13.0

a) Results for this period consolidate the acquired EPI business for the post acquisition period, from 15 February 2018 to 30 September 2018.

In the third quarter, production in Germany was broadly flat, averaging 12.4 kboepd. Production modestly increased in September following completion of the acquisition of a portfolio of assets from Wintershall DEA. However, the gains were offset by minor project delays at Rӧmerberg. Production is expected to increase in the fourth quarter to reflect a full contribution from the acquired assets and the Rӧmerberg 7 well, which came onstream in October. Operating costs in the quarter averaged $20.4/boe (excluding royalties), reflecting our continued efforts to drive our cost base lower and remain on track to deliver a reduction in opex (excluding royalties) by the end of the year. Development and exploration During the third quarter we commenced drilling operations on the Schwegenheim exploration well. We plan to spud the Adorf Z15 and Ringe 6 wells in November and drill the Rühlermoor 273a and 353a side-tracks before the end of the year. We will also test two existing Reitbrook-Alt production wells in the Hamburg oil field using Radial Jetting technology. If successful, the application of this technology could potentially extend the life of the field significantly. Recompletion of the Rӧmerberg 5 well and drilling the new Rӧmerberg 6 well has been deferred until 2020. During the fourth quarter we expect to finalise FEED for further development of the Bramberge oil field, which will include one new well, two side-tracks and additional surface facilities. North Africa Production

Neptune Energy – North Africa Q3 2019 Q2 2019 Q1 2019 YTD 2019 2018 (note a) 3 months to 30 Sept 2019 3 months to 30 June 2019 3 months to 31 March 2019 9 months to 30 Sept 2019 15 Feb – 30 Sept 2018

Gas production (kboepd) 3.3 2.9 2.8 3.0 3.1 Liquid production (kbpd) 1.4 1.5 1.6 1.5 1.1 Total production (kboepd) 4.7 4.4 4.4 4.5 4.2 Gas production equity accounted affiliates (kboepd) 0.7

• 0.2
• Total production (kboepd) including equity

accounted affiliates 5.4 4.4 4.4 4.7 4.2

a) Results for this period consolidate the acquired EPI business for the post acquisition period, from 15 February 2018 to 30 September 2018. b) Figures only include production from wholly affiliates

In September, we successfully brought the Touat gas development project in Algeria onstream. Production is currently ramping up towards plateau, albeit at a slower pace than previously anticipated. The operations team is currently working through final troubleshooting issues, which will help establish plant stability and safe operations. For the third quarter, Touat contributed 0.7 kboepd, which is expected to increase to around 16 kboepd at plateau.

Neptune Energy Group Midco Limited Report for the period ended 30 September 2019 10

In Egypt, production increased by 0.3 kboepd to 4.7 kboepd in the third quarter. Production was higher following completion of the Karam-10 well in August, having been brought forward from 2020. There were also positive results from infill oil wells and the Ashrafi workover campaign. Operating costs in Egypt were slightly higher in the third quarter at $10.0/boe due to workover costs, the BED 3 shutdown, higher diesel costs and currency movements. Development and exploration In Egypt, we continue to evaluate business development opportunities to build materiality in our North Africa business. In December, we expect to finalise the formalities of signing the new North West El-Amal concession, located in the Gulf of Suez and adjacent to the prolific Morgan and Ramadan fields, allowing us to acquire modern 3D seismic data in 2020. This is Neptune’s first operated licence in Egypt. Asia Pacific Production

Neptune Energy – Asia Pacific Q3 2019 Q2 2019 Q1 2019 YTD 2019 2018 (note a) 3 months to 30 Sept 2019 3 months to 30 June 2019 3 months to 31 March 2019 9 months to 30 Sept 2019 15 Feb – 30 Sept 2018

Gas production (kboepd) 3.3 3.0 2.7 3.0

• Gas production for sale as LNG (kboepd)

12.7 15.6 16.6 14.9 20.0 Liquid production (kbpd) 0.6 0.6 0.7 0.6 0.7 Total production (kboepd) 16.6 19.2 20.0 18.5 20.7

a) Results for this period consolidate the acquired EPI business for the post acquisition period, from 15 February 2018 to 30 September 2018.

In Indonesia, production in the third quarter averaged 16.6 kboepd, reflecting offtake restrictions, which has limited production to

• ur annual contracted volume. The reduction in cargoes lifted are in response to weaker demand for LNG in Asia in the third quarter,

leading to higher inventory levels at Bontang. While we believe this is a short-term issue, we anticipate a risk of some curtailment in 2020 and have protection through take-or-pay provisions in our gas sales agreements. Operating costs were $18.5/boe, reflecting lower production, C3/4 purchases and higher transportation costs. Development and exploration We expect our acquisition of interests in the East Sepinggan PSC and the East Ganal PSC to close in the fourth quarter. The West Ganal PSC, containing the Maha discovery, was officially signed in October. In East Sepinggan, the Merakes discovery is under development. The Merakes field is being developed as a tie-back to the Jangkrik FPU, which has a maximum inlet gas capacity of 750 mmcfpd after

• debottlenecking. With Jangkrik production coming off plateau, production from new fields will progressively increase, filling the

Jangkrik FPU capacity. First gas from Merakes is expected in the fourth quarter of 2020. The Merakes field will be followed by development of additional discovered (and to be discovered) resources in the basin as we aim to keep the Jangkrik FPU at full capacity. The Merakes development drilling campaign is already underway. In 2020, an exploration well at Maha will be drilled and tested.

Neptune Energy Group Midco Limited Report for the period ended 30 September 2019 11

Summary of production by area - wholly owned affiliates

Q3 2019 Q2 2019 Q1 2019 Sept YTD 2019 Sept YTD 2018 (note 1)

Gas production (kboepd)

Norway 20.4 26.2 26.9 24.5 29.0 UK 14.7 16.4 16.3 15.8 18.1 The Netherlands 17.1 19.2 23.0 19.7 27.0 Germany 6.7 6.9 7.3 7.0 7.2 North Africa 3.3 2.9 2.8 3.0 3.1 Asia Pacific 3.3 3.0 2.7 3.0

• Total Gas production (kboepd)

65.5 74.6 79.0 73.0 84.4

Gas production for sale as LNG (kboepd)

Norway 13.5 13.5 12.5 13.1 13.7 Asia Pacific 12.7 15.6 16.6 14.9 20.0

Total Gas production for sale as LNG (kboepd)

26.2 29.1 29.1 28.0 33.7

Liquid production (kbpd) (note 2)

Norway 29.4 32.8 32.8 31.7 31.7 UK 0.3 0.4 0.4 0.4 0.5 The Netherlands 1.0 1.0 2.7 1.6 2.6 Germany 5.7 5.6 5.5 5.6 5.8 North Africa 1.4 1.5 1.6 1.5 1.1 Asia Pacific 0.6 0.6 0.7 0.6 0.7

Total Liquid production (kbpd)

38.4 41.9 43.7 41.4 42.4

Total production (kboepd)

Norway 63.3 72.5 72.2 69.3 74.4 UK 15.0 16.8 16.7 16.2 18.6 The Netherlands 18.1 20.2 25.7 21.3 29.6 Germany 12.4 12.5 12.8 12.6 13.0 North Africa 4.7 4.4 4.4 4.5 4.2 Asia Pacific 16.6 19.2 20.0 18.5 20.7

Total production (kboepd)

130.1 145.6 151.8 142.4 160.5

1) Daily average production over the period 15 February 2018 to 30 September 2018. 2) Liquid includes oil and condensate and other natural gas liquids.

Neptune Energy Group Midco Limited Report for the period ended 30 September 2019 12

Summary of production by area – equity accounted affiliates

Q3 2019 Q2 2019 Q1 2019 Sept YTD 2019 Sept YTD 2018 (note 1)

Gas production (kboepd)

North Africa 0.7

• 0.2
• Total Gas production (kboepd)

0.7

• 0.2
• Summary of production by area – wholly owned and equity accounted affiliates

Q3 2019 Q2 2019 Q1 2019 Sept YTD 2019 Sept YTD 2018 (note 1)

Total production (kboepd)

Norway 63.3 72.5 72.2 69.3 74.4 UK 15.0 16.8 16.7 16.2 18.6 The Netherlands 18.1 20.2 25.7 21.3 29.6 Germany 12.4 12.5 12.8 12.6 13.0 North Africa 5.4 4.4 4.4 4.7 4.2 Asia Pacific 16.6 19.2 20.0 18.5 20.7

Total production (kboepd)

130.8 145.6 151.8 142.6 160.5

1) Daily average production over the period 15 February 2018 to 30 September 2018.

Neptune Energy Group Midco Limited Report for the period ended 30 September 2019 13

Financial review

This report includes the group results for the nine months ended 30 September 2019. On 1 September 2019, we completed the asset acquisition in the Emsland region of Germany of certain oil and gas fields from Wintershall Dea. The comparative results include the acquisition of ENGIE E&P International S.A. (‘EPI’) since 15 February 2018 as that is when Neptune acquired control over EPI and received the economic benefit of cash-flows of this business. The acquisition of 100 per cent of the share capital of VNG Norge, for cash consideration, was completed on 28 September 2018 and the results of VNG Norge were consolidated from the start of the fourth quarter 2018. In accordance with IFRS standards for accounting for business combinations, we have recorded the acquired assets and liabilities of EPI and VNG Norge as at the acquisition date at their fair values, or otherwise as required by IFRS. Oil and gas assets acquired were recorded at the net present value of expected future cash flows, post-tax, based on independent reserves reports, management plans and expectations and using projections of oil and gas prices based on a combination of forward prices and long-term Company

• assumptions. Liabilities were established in respect of decommissioning costs, post-employment benefits and deferred taxes.

The unaudited results for the period ended 30 September 2018 as previously disclosed have been revised as they were based on provisional assigned fair values of the acquisition of the EPI and VNG Norge business on 15 February 2018. On conclusion of the business combination accounting for the audited results for the year ended 31 December 2018 for EPI the associated judgements and fair values were subsequently concluded. Consequently, to ensure a more appropriate comparison, the 30 September 2018 comparative financial results and associated metrics incorporate this concluded position. The revisions to these unaudited financial statements and metrics did not constitute a restatement of the financial results as International Financial Reporting Standards allow a period of up to 12 months beyond the acquisition date of business combinations to finalise the associated judgements and assigned fair values. The business combination accounting of EPI resulted in the final recognition of $627.0 million of goodwill and the acquisition of VNG Norge resulted in the final recognition of goodwill of $80.7 million. In each case, the goodwill arises largely as a result of the requirement to recognise deferred tax liabilities in respect of temporary differences between the fair value of oil and gas assets recorded in PP&E and their tax base available as future tax deductions. The assigned fair values for the EPI and the VNG business are now final. Results of operations

$ millions 9 months ended 30 September 2019 9 months ended 30 September 2018 (note a) Revenue 1,679.2 1,767.4 Operating profit (note c) 688.1 851.2 Profit before tax 445.2 675.3 Net profit 83.2 152.5 EBITDAX for RBL (note b) 1,213.2 1,330.6 Net profit before acquisition-related expenses (note d) 83.2 214.9 Cash flow from operations, after tax before acquisition related expenses (note d) 947.2 884.9 Adjusted development cash capital expenditure (note e) 650.1 258.0 Net debt (note f) 1,086.3 901.0 Net Debt/EBITDAX (RBL) (notes f & g) 0.62x 0.45x

a) Results for this period consolidate the acquired EPI business for the post acquisition period only, from 15 February 2018 to 30 September 2018. b) EBITDAX (as defined by the RBL and Shareholder agreements). c) Operating profit comprises current operating income after share in net income of entities accounted for using the equity method and is stated before tax, finance costs, mark- to-market

• n commodity contracts and non-recurring items.

d) Adjusted for acquisition-related expenses and taxes of $62.4 million in 2018 incurred in connection with the EPI and VNG Norge acquisitions. e) Includes expenditure of $48.0 million for period to 30 September 2019 and $38.6 million for period from 15 February to 30 September 2018 in respect of the Touat project, held by a joint venture company which Neptune accounts for under the equity method. f) Net debt excludes Subordinated Neptune Energy Group Limited Loan and Touat Project finance facility as defined by the RBL and Shareholder agreements. g) EBITDAX is based on a 12 month rolling average value of $1,765.7m (2018: $2,002.1m), as defined by the RBL and Shareholder agreements. As Neptune only completed the acquisition

• f Engie on 15th February 2018, the 2018 12 month rolling average EBITDAX value of $2,002.1m is calculated on a pro-forma basis assuming Neptune had owned the business from 1

October 2017.

Neptune Energy Group Midco Limited Report for the period ended 30 September 2019 14

Total sales for the nine months ended 30 September 2019 were $1,679.2 million, reflecting total production of 38.8 mmboe (for wholly owned affiliates) and realised prices, before and after hedging, as shown in the table below. The Brent crude price averaged $64.8 per barrel for the nine months ended 30 September 2019 and our average realised oil price (pre hedging) was $62.1 per barrel for the same period. The LNG sales prices are linked to a combination of movements in oil and gas market prices, depending on the contract. Realised prices data:

Q3 2019 Q2 2019 Q1 2019 9 months ended 30 Sept 2019 15 February to 30th September 2018 (note a)

Excluding impact of hedging:

Average realised gas price ($/mcf) 3.6 4.4 6.5 5.0 7.8 Average realised LNG price ($/mcf) 7.9 8.1 9.0 8.4 7.6 Average realised oil price ($/bbl) 64.2 65.9 58.5 62.1 70.7 Average realised price, other liquids ($/bbl) (note b) 23.2 39.1 42.2 36.8 49.1

Including impact of hedging:

Average realised gas price ($/mcf) 4.6 5.0 6.5 5.5 6.6 Average realised LNG price ($/mcf) 7.9 8.1 9.0 8.4 7.6 Average realised oil price ($/bbl) 64.2 64.6 57.8 61.3 64.1 Average realised price, other liquids ($/bbl) (note b) 23.2 39.1 42.2 36.8 49.1 a)

Results for this period consolidate the acquired EPI business for the post acquisition period, from 15 February 2018 to 30 September 2018

b)

Other liquids includes condensate and other natural gas liquids

Operating costs were $411.9 million for the nine months to 30 September 2019 and our average operating cost per boe produced was $10.6/boe. This compares with average operating cost per boe of $10.2/boe for 2018 full year. Operating costs for the purpose

• f per boe expense are increased by $5.5 million (2018 full year: $24.7 million reduction) for the nine months ended 30 September

2019 to exclude changes in the value of under-lifted entitlement to production and to net-off income from tariffs and services which serve to recover costs. Pro-rata costs incurred in the period of 15 February to 30 September 2019 are 21% lower than in the same period in 2018 driven by lower production. Depreciation and amortisation expense of $487.0 million (2018: $434.2 million) reflects the uplift in asset carrying values as a result

• f the fair valuation of assets for the business combination in 2018. The charge represents $12.5/boe produced compared to

$11.9/boe produced per the period 15 February to 30 September 2018 and is predominantly due to the impact of field production curtailments in Norway and unplanned production outages in Netherlands. Exploration expense for the period was $36.9 million (2018: $46.0 million) which included costs incurred on G&G studies to review strategic growth opportunities and lower seismic costs for data purchases predominantly in Norway and UK compared to 2018. General and administration expense of $58.0 million for the period to 30 September 2019 consists primarily of 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. G&A expenses incurred in the nine months of 2019 are broadly in line with G&A incurred in the period of 15 February to 30 September 2018. Share in net income of entities accounted for under the equity method represents tariff income of one of our Dutch pipeline interests and the Touat joint venture which commenced production in September 2019. The Group’s operating profit for period to 30 September 2019 was $688.1 million before net finance costs and the impact of one-off group reorganisation costs of $68.0 million. EBITDAX (as defined by the RBL shareholders agreement) for the same period was $1,213.2 million, compared with $1,330.6 million for the period 15 February to 30 September 2018. The decrease in EBITDAX principally reflects lower realised commodity prices and lower production in the period offset in part by the effect of consolidating a full nine months result from the EPI acquisition. The prior period, other operating expenses includes non-recurring acquisition-related expenses of $62.4 million, reflecting the requirement to charge business combination transaction expenses and related costs (such

Neptune Energy Group Midco Limited Report for the period ended 30 September 2019 15

as taxes levied in respect of share transfers and change of control) to net income. In addition, 2019 includes $13.4 million in relation to an impairment of the Orca licence asset and the Sigrun appraisal well. In 2018 no impairment expense was required. Net financing expenses were $160.5 million for the period and include $104.8 million of interest expense (cash impact $83.8 million) and unwinding of discount on abandonment provisions of $28.2 million. The tax charge for the period represents 81 per cent of pre-tax income which includes restructuring costs of approximately $68.0 million on which limited tax relief is presently assumed. Adjusting for these costs, the effective tax rate would be 71 per cent of pre- tax income. Net income for the period ended 30 September 2019 was $83.2 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 30 September 2019, the approximate share of post-tax production hedged for future periods is shown in the table below. For

• il, weighted average downside protection was $61/barrel for the remainder of 2019 and $61/barrel for 2020, with upside capped

at around $75/barrel in 2019 and $76/barrel in 2020 for those hedged volumes. For gas, hedging provided weighted average floor prices of $5.7/mmbtu for 2019, $5.7/mmbtu for 2020, $5.7/mmbtu for 2021 and $5.9/mmbtu for 2022, with upside caps at $7.3/mmbtu, $7.2/mmbtu , $7.2/mmbtu and $8.2/mmbtu respectively. Aggregate post-tax hedge ratio:

2019 2020 2021 2022 Oil 49% 17%

• Gas

65% 71% 54% 4% Total 58% 44% 23% 1%

1) Oil price hedges include hedges of realisations for gas production sold as LNG and priced in relation to oil prices. 2) Post--tax hedge ratios adjust for different tax rates on physical sales and hedge gains and losses, which mean that effective post-tax hedges can be achieved through hedging contracts for volumes which may be significantly less than anticipated sales. 3) Hedge percentages are based on an equity case which excludes the likely impact of the recent Edison acquisition announcement which is yet to complete.

The estimated net fair value (comprised of current and non-current assets and liabilities) on a mark-to-market basis of all our commodity derivative instruments at 30 September 2019, was an asset of $57.8 million, of which $10.8 million relates to contracts expiring in 2019. Cash flow Operating cash flow, after cash taxes, for the period to 30 September 2019 was $947.2 million. Cash taxes were $261.0 million and largely relate to Norwegian taxes. The effective rate of cash tax as a percentage of pre-tax operating cash flow was 22 per cent. Capital expenditure Cash capital expenditure for the period to 30 September 2019, was $630.8 million, including $28.7 million of capitalised exploration

• expenditure. This figure is significantly higher than the corresponding period last year as a result of expenditure on new development

projects, primarily Njord, Duva, P1 and Fenja. 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 $50.3 million in the period.

$ millions 9 months ended 30 September 2019 9 months ended 30 September 2018 (note a) Investing cash flows: Development capex 601.0 219.4 Acquisitions – assets 1.1

• Exploration capex

28.7 11.8 Acquisitions - business combinations

• 3,546.5

Total cash capital expenditure 630.8 3,558.3

a) Results for this period consolidate the acquired EPI business for the post acquisition period, from 15 February 2018 to 30 September 2018.

Neptune Energy Group Midco Limited Report for the period ended 30 September 2019 16

Total exploration expenditure comprised the $28.7 million cash capex and $36.9 million expensed in respect of G&G costs. Development cash capex was $602.1 million. The majority of spend was in Norway on the Duva/Gjøa P1 and Fenja project as well as progressing projects in UK and Indonesia. This compares to capital expenditure for the nine months ended 30 September 2018 of $219.4 million. We incurred $36.6 million on decommissioning expenditure in the period to 30 September 2019, this was principally in the UK in relation to our equity share in our non-operated CMS assets and other legacy non-operated fields. Acquisitions On 26 July, the Group announced it had agreed to acquire interests in two Production Sharing Contracts (PSC) in the Kutei basin, offshore Indonesia (a 20 per cent working interest in the East Sepinggan PSC and a 30 per cent working interest in the East Ganal PSC). The transaction is subject to customary regulatory approvals, with completion expected in the fourth quarter of 2019. On 29 July, the Group announced an agreement to acquire interests in certain oil and gas fields in Germany from Wintershall

• Dea. The Company is already a joint venture partner in the assets and operates the Bramberge oil field and the Grafschaft

Bentheim gas fields, adding approximately 600 boepd to the Company’s production in Germany. This deal completed in early September 2019. On 26 August, the Group announced it and its partners Eni (Operator) and Pertamina had been awarded the West Ganal PSC in Indonesia, also located in the Kutei basin. The consortium has committed to drilling four exploration wells during the first exploration period, in addition to acquiring seismic data. On 14 October, the Group announced a conditional agreement with Energean Oil and Gas plc to acquire Edison E&P’s UK and Norwegian producing, development and exploration assets for an initial cash consideration of $250 million, to be adjusted for working capital (effective date January 1, 2019). A contingent consideration of up to $30 million may be paid by the end of 2026 if certain conditions are met. At completion, we will acquire the entire issued share capital of Edison E&P UK Ltd, Euroil Exploration Limited and Edison Norge AS. The purchase is contingent on Energean completing its proposed acquisition of Edison E&P. The acquisition will provide the Group with growth in contingent resources, an estimated 30 MMboe of 2P reserves and near term production in core areas of the North Sea close to our existing infrastructure. In the nine months ended 30 September 2018, the expenditure on acquisitions totalled $3,546.5 million of which $3,205.2 million relates to the EPI acquisition, including adjustment payments and receipts under the sale and purchase agreement (SPA) which arose subsequent to closing and associated acquisition costs of $60.4 million and a further $341.3 million related to the acquisition of VNG Norge A/S. 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 0.62x despite lower commodity prices during the quarter and lower production in 3Q19 vs 1H19. We funded our business mainly with cash generated from operations and loan facilities. At 30 September 2019, we had the following debt outstanding:  $720 million drawn under a $2 billion, committed Reserve Base Lending (RBL) facility, which matures in 2024;  $550 million of senior notes, paying a 6.625% coupon, maturing in 2025;  $113.2 million Subordinated Neptune Energy Group Limited loan, maturing 2024; and  $243.9 million project finance facility for Touat, (which is repayable from net revenues of the project)  $35 million drawn under a short term borrowing facility At 30 September 2019, our cash balance totalled $159.2 million and our available and undrawn headroom under the RBL was $1,199

• million. We also had $96 million of letters of credit outstanding, of which $81 million was drawn down under an ancillary facility under

the RBL. Our weighted average cost of borrowing for the Group was 5.7%.

Neptune Energy Group Midco Limited Report for the period ended 30 September 2019 17

Our Corporate Credit Rating has not changed over the quarter and we continue to have a positive outlook from both Moody’s and S&P, which rate us respectively at Ba3 and BB-. Fitch assigned Neptune an inaugural rating, in May 2019, of BB with a stable outlook. We will continue to seek to further strengthen these ratings over time. All debt, with the exception of the RBL, is carrying a fixed interest rate. However, we swapped a sizeable amount of the RBL into fixed rate debt, taking advantage of historically low interest rates available in the market earlier in 2018. As a result, 79 per cent of the debt portfolio at 30 September 2019 was fixed rate, which reduces Neptune exposure to increases in the USD Libor interest rate. On 25 October, the Group via its wholly owned subsidiary Neptune Energy Bondco plc issued an aggregate principal amount of $300 million of 6⅝% senior notes due 2025 which represent an addional issuance of the series of which an aggregate principal amount

• f $550 million were previously issued.

Financial condition Operating cash flows of $947.2 million more than covered investing cash flows of $665.8 million and after financing costs and net debt repayment of $317.7 million during the period resulted in a net cash outflow of $36.3 million for the period to 30 September

• 2019. We ended the period with gross interest-bearing debt of $1,602.7 million (book value) and net debt (excluding Subordinated

Neptune Energy Group Limited loan and Touat Project finance facility) of $1,086.3 million. This represents a Net Debt to EBITDAX (excluding Touat cash flows) ratio of 0.62 times for the twelve months ending 30 September 2019. 2019 outlook Lower than expected production in the third quarter, coupled with a slower ramp up at Touat, has resulted in us revising our average production guidance for the full year to around 145 kboepd. Higher production is expected for the fourth quarter of the year due to Touat coming onstream, as well as the impact of three infill wells being drilled at Fram. The full year 2019 development capex is expected to be in the region of $750 million, before the impact of M&A activities. We expect operating cost per boe to average around $10.5/boe for the full year. Risks and Uncertainties Investment in Neptune involves risks and uncertainties, these are summarised in detail in the Neptune Energy 2018 Annual Report and Accounts page 10. 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, fluctuation 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.

Neptune Energy Group Midco Limited Report for the period ended 30 September 2019 18

NEPTUNE ENERGY GROUP MIDCO LIMITED UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS For the nine months ended 30 September 2019

Neptune Energy Group Midco Limited Unaudited Condensed Consolidated Financial Statements For the nine months ended 30 September 2019

Neptune Energy Group Midco Limited Report for the period ended 30 September 2019 19

Unaudited Condensed Consolidated Statement of Profit and Loss

In millions of US$ Notes Nine months ended 30 September 2019 Nine months ended 30 September 2018 Revenue 3 1,679.2 1,767.4 Cost of sales (895.6) (817.9) GROSS PROFIT 783.6 949.5 Exploration expenses (36.9) (46.0) General and administration expenses (58.0) (56.2) Share of net income from investments using equity method (0.6) 3.9 OPERATING PROFIT AFTER EQUITY ACCOUNTED INVESTMENTS 3 688.1 851.2 Other operating (losses)/gains 5 (82.4) (95.5) OPERATING PROFIT BEFORE FINANCIAL ITEMS 605.7 755.7 Finance costs (165.8) (83.7) Finance income 5.3 3.3 PROFIT BEFORE TAX 445.2 675.3 Taxation 6 (362.0) (522.8) NET PROFIT 83.2 152.5

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

Unaudited Condensed Consolidated Statement of Other Comprehensive Income

In millions of US$ Notes Nine months ended 30 September 2019 Nine months ended 30 September 2018 Profit for the Period 83.2 152.5 Other comprehensive Income: Items that may be reclassified to the Profit and Loss Hedge adjustments net of tax (note 1) 12 41.2 (170.0) Foreign currency translation (53.3) (80.1) Other items: Re-measurement of defined pension obligations, net of tax

• Other comprehensive income

(12.1) (250.1) Other comprehensive profit/(loss) for the period, net of tax 71.1 (97.6) 1) In 2019 Income tax related to hedge adjustments is a charge of $11.3 million.

Neptune Energy Group Midco Limited Unaudited Condensed Consolidated Financial Statements For the nine months ended 30 September 2019

Neptune Energy Group Midco Limited Report for the period ended 30 September 2019 20

Unaudited Condensed Consolidated Statement of Financial Position

In millions of US$ Notes 30 September 2019 31 December 2018 NON-CURRENT ASSETS Goodwill 619.8 648.1 Intangible assets 7 108.7 111.2 Property, plant and equipment 8 3,990.7 3,922.2 Derivative instruments 12 56.4 40.1 Investments in entities accounted for using the equity method 585.8 540.9 Other non-current assets 29.2 8.8 Equity instruments 12 18.7 19.7 Deferred tax assets 452.2 438.6 TOTAL NON-CURRENT ASSETS 5,861.5 5,729.6 CURRENT ASSETS Derivative instruments 12 63.4 33.2 Trade and other receivables 619.2 642.6 Inventories 60.5 64.3 Cash and cash equivalents 9 159.2 197.3 Tax receivable 43.4 83.7 TOTAL CURRENT ASSETS 945.7 1,021.1 TOTAL ASSETS 6,807.2 6,750.7 Share capital 13 1,977.2 1,977.2 Hedging reserve 16.1 (25.1) Foreign currency translation (196.1) (142.8) Retained earnings (deficit) (39.2) (122.4) TOTAL EQUITY 1,758.0 1,686.9 NON-CURRENT LIABILITIES Provisions 11 1,613.9 1,675.2 Long-term borrowings 12 1,508.9 1,788.2 Derivative instruments 12 45.6 31.1 Income tax payable 51.1 35.7 Other non-current liabilities 10 154.2 59.6 Deferred tax liabilities 684.9 582.2 TOTAL NON-CURRENT LIABILITIES 4,058.6 4,172.0 CURRENT LIABILITIES Provisions 11 142.8 69.3 Short-term borrowings 12 93.8

• Derivative instruments

12 34.1 73.6 Trade and other payables 10 154.4 94.5 Income tax payable 10 220.9 188.1 Other current liabilities 10 344.6 466.3 TOTAL CURRENT LIABILITIES 990.6 891.8 TOTAL EQUITY AND LIABILITIES 6,807.2 6,750.7

Neptune Energy Group Midco Limited Unaudited Condensed Consolidated Financial Statements For the nine months ended 30 September 2019

Neptune Energy Group Midco Limited Report for the period ended 30 September 2019 21

Unaudited Condensed Consolidated Statement of Changes in Equity

In millions of US$ Share Capital Hedging reserve Foreign currency translation Retained Surplus/(Deficit) Total As at 1 January 2019 1,977.2 (25.1) (142.8) (122.4) 1,686.9 Profit for the period

• 83.2

83.2 Other comprehensive income for the period

• 41.2

(53.3)

• (12.1)

Total comprehensive income for the period

• 41.2

(53.3) 83.2 71.1 Transactions with Owners of the Company: Issue of ordinary shares related to business combinations

• Balance 30 September 2019

1,977.2 16.1 (196.1) (39.2) 1,758.0 The hedging reserve is shown net of tax of $8.0m. In millions of US$ Share Capital Hedging reserve Foreign currency translation Retained Surplus/(Deficit) Total As at 1 January 2018

• (3.8)

(3.8) Profit for the period

• 152.5

152.5 Other comprehensive income for the period

• (170.0)

(80.1)

• (250.1)

Total comprehensive income for the period

• (170.0)

(80.1) 152.5 (97.6) Transactions with Owners of the Company: Issue of ordinary shares related to business combinations 1,977.2

• 1,977.2

Total Contributions and Distributions 1,977.2 (170.0) (80.1) 152.5 1,879.6 Balance 30 September 2018 1,977.2 (170.0) (80.1) 148.7 1,875.8

Neptune Energy Group Midco Limited Unaudited Condensed Consolidated Financial Statements For the nine months ended 30 September 2019

Neptune Energy Group Midco Limited Report for the period ended 30 September 2019 22

Unaudited Condensed Consolidated Cash Flow Statement

In millions of US$ Nine months ended 30 September 2019 Nine months ended 30 September 2018 Cash Flows from Operating Activities Profit before taxation 445.2 675.3 Adjustments to reconcile profit before tax to net cash flows: Depreciation, amortisation and provisions 500.4 443.1 Unsuccessful exploration costs written off 0.4

• Finance costs

165.8 83.7 Finance income (5.3) (3.3) Net income from equity investments 0.6 (3.9) Other non-cash income and expenses 72.3

• Fair value movement on commodity based derivative instruments

(3.4) 27.6 Movement in provisions including decommissioning expenditure (54.7) (34.2) Working capital adjustments 86.9 (72.2) Income tax paid (261.0) (293.6) Net cash flows from operating activities 947.2 822.5 Cash Flows from Investing Activities Expenditure on exploration and evaluation assets (28.7) (11.8) Expenditure on property, plant and equipment (602.1) (219.4) Expenditure on business combination and acquisitions, net of cash acquired

• (3,546.5)

Proceeds from sale of exploration and evaluation assets 10.0

• Finance income received

5.3 3.3 Investment made in equity accounted investments (50.3)

• Net cash flows used in investing activities

(665.8) (3,774.4) Cash Flows from Financing Activities Proceeds from issue of shares

• 1,977.2

Proceeds from loans and borrowings 416.5 2,435.0 Repayment of borrowings (635.0) (1,033.5) Expenditure on right of use assets (15.4)

• Finance costs paid

(83.8) (113.7) Net cash flows from/(used in) financing activities (317.7) 3,265.0 Net increase/(decrease) in cash and cash equivalents (36.3) 313.1 Cash and cash equivalents at 1 January 197.3 0.4 Net foreign exchange differences (1.8) (6.7) Cash and cash equivalents at 30 September 159.2 306.8

Neptune Energy Group Midco Limited Unaudited Condensed Consolidated Financial Statements For the nine months ended 30 September 2019

Neptune Energy Group Midco Limited Report for the period ended 30 September 2019 23

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 nine months ended 30 September 2019 were authorised for issue in accordance with a resolution of the Board on 21 November 2019. The Group is principally engaged in oil and gas exploration and production. The information for the period ended 31 December 2018 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 2018 were approved by the Board of Directors on 2 April 2019 and delivered to the Registrar of Companies. The auditor reported on those accounts; the report was unqualified 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 nine months ended 30 September 2019 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 2018 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 2018 except where, due to the adoption of new standards effective as of 1 January 2019 (see note 1.1). The Group has not early-adopted any other standard, interpretation

• r amendment that has been issued but is not yet effective.

The unaudited results for the period ended 30 September 2018 as previously disclosed have been adjusted as they were based on provisional assigned fair values of the acquisition of the EPI business on 15 February 2018. On completion of the business combination accounting for the audited results for the year ended 31 December 2018 the associated judgements and fair values were subsequently

• concluded. Consequently, to ensure a more appropriate comparison, the 30 September 2018 comparative financial results (which

consolidate the acquired EPI business from 15 February) and associated metrics incorporate this concluded position. The revisions to these unaudited financial statements and metrics do not constitute a restatement of the financial results as International Financial Reporting Standards allow a period of up to 12 months beyond the acquisition date of business combinations to finalise the associated judgements and assigned fair values.

1.1 New standards, interpretations and amendments adopted by the Group

IFRS 16 Leases was issued in 2016 to replace IAS 17 Leases and is required to be adopted by 2019. Under the new standard all lease contracts, with limited exceptions, are recognised in financial statements by way of right-of-use assets and corresponding lease liabilities. The Group has applied the modified retrospective approach, which means that the cumulative effect of initially applying the standard is recognised at the date of initial application and there is no restatement of comparative information. In March 2019, the IFRS Interpretations Committee (IFRIC) finalised its decision regarding “liabilities in relation to a Joint Operator’s Interest in a Joint Operation (IFRS 11 Joint Arrangements)”, concluding that a joint operator should recognise the liabilities for which it has primary responsibility, which may be different from its share in the joint operation. As a consequence of this ruling the Group has recognised the full value of joint venture lease liabilities for which it has primary responsibility, recognising its joint venture share as a right of use asset and the partners share as a joint venture receivable. The application of the standard has impacted both the measurement and disclosures of leases over a low-value threshold, with terms longer than one year and on the classification of expenditures and consequently the classification of cash flow from operating activities, cash flow from investing activities and cash flow from financing activities. It has also impacted the timing of expenses recognised in the statement of

• income. The adoption of the new standard at 1 January 2019, on a gross basis has had a negligible impact on equity following the recognition
• f lease liabilities of $155 million and additional right of use assets of $90 million and JV partner receivables of $65 million. These liabilities

have been measured at the present value of the remaining lease payments, discounted using the Group’s marginal cost of finance as of 1 January 2019, which is the Company’s rate on its corporate reserve-based lending facility currently 5.7 per cent. A 1 per cent change in the cost of borrowing would have impacted the value of lease liabilities on transition by $5.4 million.

Neptune Energy Group Midco Limited Unaudited Condensed Consolidated Financial Statements For the nine months ended 30 September 2019

Neptune Energy Group Midco Limited Report for the period ended 30 September 2019 24

The following categories of leases have been identified: land, buildings (offices, warehouses and supply bases), transportation assets (helicopter, supply and standby vessels), Plant, Property and Equipment. Where the asset is dedicated to an Operated Joint Venture and Neptune has transferred substantially all the risks and rewards incidental to

• wnership on a pro rata base to joint venture (JV) partner(s) Neptune recognises the gross lease liability but derecognises the proportion of

the right of use asset that is sub leased which is recognised as a JV receivable. Where there are options to extend a contract and it is reasonably certain that the contract will be extended the lease period extension is included in the assessment. The right of use asset is recognised within property plant and equipment at the present value of the liability at the commencement date of the lease, adding any directly attributable costs. The right-of-use asset is depreciated on a straight-line basis over the lease term. The Group has elected to use the exemptions proposed by the standard on lease contracts for which the lease terms ends within 12 months as of the date of initial application, and lease contracts for which the underlying asset is of low value. These leases will continue to be accounted as operating leases and are not material in the context of the Group financial results. Furthermore, the use of a single discount rate is applied to a portfolio of leases with reasonably similar characteristics. The impact of adopting IFRS 16 on 1 January 2019 has been the immediate recognition of right-of-use assets of $116 million, a JV partner receivable of $39 million and lease liabilities of circa $155 million, with a reclassification of costs from 1 January 2019 that would have previously been reported under operating lease expenses to depreciation of leased assets and unwinding of the discount on leased assets.

Initial recognition of lease liability Current Non-current Value on transition $m Land 2 13 15 Buildings 10 36 46 Transportation 24 69 93 Plant, Property and Equipment

• 1

1

Total

36 119 155

The difference between the closing 2018 value of operating lease commitments of $189 million and the opening value to be recognised as the lease liability of $155 million is $34 million. This arises primarily as a result of the deduction of $97 million of items outside the scope of IFRS 16 reporting, being pipeline capacity commitments and jointly shared assets, offset by the addition of $103 million of items within the scope of IFRS 16 while previously being outside the scope of IAS 17. These are extension options reasonably certain to be exercised, the inclusion of gross attribution of contracted assets within operated joint operations and $40 million as a result of applying a discount rate of 5.7 per cent being the Group’s incremental borrowing rate.

In millions of US$

Reconciliation of Operating Lease Commitments to IFRS 16 liability

1 January 2019 Operating lease commitments as at 31 December 2018 as disclosed in the Group's Consolidated Financial Statements 189 Recognition exemption- jointly controlled assets (note a) (11) Recognition exemption- pipeline booking capacity commitments (86) Extension options reasonably certain to be exercised 60 Leases within Joint Operations 43 Discounted using incremental borrowing rate at 1 January 2019 of 5.7% (40)

Lease liabilities recognised at 1 January 2019

155

a) Also includes the recognition exemption for low- value assets and short-term leases of $0.1 million

IFRIC 23 Uncertainty over Income Tax Positions (effective 1 January 2019) IFRIC 23, Uncertainty over Income Tax Treatments, was issued by IASB on 7 June 2017. The interpretation provides guidance on the accounting for current and deferred tax assets and liabilities in circumstances in which there is uncertainty over income tax treatments. IFRIC 23 requires the entity to contemplate whether uncertain tax treatments should be considered separately or as a group based on the predictability of the

• resolution. In addition, the entity should assess if the tax authority will accept uncertain tax treatments, and in the case where it is not

probable, the interpretation requires the entity to reflect the uncertainty with disclosure of the most likely amount and the expected value

• f the income tax payable or recoverable. The interpretation became effective for annual periods beginning on January 1, 2019. The adoption
• f this interpretation did not have a material impact on the condensed consolidated interim financial statements.

Neptune Energy Group Midco Limited Unaudited Condensed Consolidated Financial Statements For the nine months ended 30 September 2019

Neptune Energy Group Midco Limited Report for the period ended 30 September 2019 25

Several other financial reporting amendments and interpretations apply for the first time in 2019, but do not have an impact on 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;  assessments of fair value of assets and liabilities acquired as part of a business combination;  calculations of depreciation and amortisation which involve estimates of volumes of commercial reserves of oil and gas;  measurement of provisions, particularly for decommissioning obligations, pensions and other employee post-retirement benefits; and measurement of recognised tax loss carry-forwards. 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

• f the volume of commercially recoverable reserves and resources of oil and gas future production rates and costs to develop reserves and

resources, and the determination of the discount rate. Any changes in these assumptions may have a material impact on the measurement of the recoverable amount and could result in adjustments to any impairment losses to be recognised. Business combination In accounting for the acquisition, as disclosed in note 4, the identifiable assets and liabilities acquired were recognised at their fair value in accordance with IFRS 3 ‘Business combinations’. The determination of their fair values is based, to a considerable extent, on estimates and judgements. Commercial reserves and depreciation of oil and gas production assets Charges for depreciation and amortisation of oil and gas producing properties are calculated on a unit of production rate based on production as a proportion of estimated quantities of proved and probable oil and gas reserves. The Group has adopted the definitions and guidelines presented in the Petroleum Resources Management System (SPE-PRMS 2007) for the classification and reporting of commercial reserves and resources of oil and gas. Commercial reserves are those in the proved and probable categories of reserves. Estimates of reserves is a subjective process involving estimating underground resource accumulations and recovery rates, and is a function

• f many factors, such as the properties of the reservoir rock and petroleum fluid. Changes in the estimates of commercial reserves will

consequently impact depreciation and amortisation expense. Changes in factors or assumptions used in estimating reserves could include:  changes due to revised estimates of volumes in place and recovery factors;  the effect on proved and probable reserves of differences between actual commodity prices and assumptions; and  unforeseen operational issues. Estimates of decommissioning 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

Neptune Energy Group Midco Limited Unaudited Condensed Consolidated Financial Statements For the nine months ended 30 September 2019

Neptune Energy Group Midco Limited Report for the period ended 30 September 2019 26

• bligations, 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. Pensions and post–employment benefit obligations 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 estimates future taxable profits. These estimates and utilisations of tax loss carry-forwards are prepared on the basis of profit and loss forecasts as included in the medium-term business plan and, if necessary, on the basis of additional forecasts. 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 or otherwise of the activity is not yet completed and there are no indications of impairment in accordance with the Group’s accounting policy. The process of determining whether there is an indicator 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 outlined above, involves complex technical judgements.

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), commodity risk, credit risk and liquidity risk. The group’s overall risk management programme focusses 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 therefore exposed to foreign exchange risk arising from various currency exposures, primarily with respect to the Pound Sterling (GBP), Norwegian Krone (NOK) and Euros. 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, hedging derivatives. For banks and financial institutions,

• nly independently rated parties with a minimum rating of ‘BBB’ are accepted.

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

3. Segment 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

• f the Group’s own oil and gas reserves and resources and is focused on seven geographical regions; UK, Norway, Netherlands, Germany,

North Africa, Asia Pacific and Corporate.

Neptune Energy Group Midco Limited Unaudited Condensed Consolidated Financial Statements For the nine months ended 30 September 2019

Neptune Energy Group Midco Limited Report for the period ended 30 September 2019 27 Nine months ended 30 September 2019 In millions of US$ UK Norway Netherlands Germany North Africa Asia Pacific Corporate 2019 Total Production revenue by origin 145.6 773.3 191.0 144.1 36.1 316.6

• 1,606.7

Other revenue 4.3 15.0 50.4 2.8

• 72.5

Revenue 149.9 788.3 2414 146.9 36.1 316.6

• 1,679.2

Current Operating Income 46.1 475.6 71.0 (9.3) 11.3 88.8 5.2 688.7 Share of net income from investments using equity method (0.6) Net Operating Profit After Equity Accounted Investments 688.1 Other operating (losses)/ gains (82.4) Profit Before Financial Items 605.7 Financial income 5.3 Finance costs (165.8) Profit Before Tax 445.2 Nine months ended 30 September 2018 In millions of US$ UK Norway Netherlands Germany North Africa Asia Pacific Corporate 2019 Total Production revenue by origin 173.8 816.0 254.1 138.6 29.2 334.0

• 1,745.7

Other revenue 8.1 1.0 7.1 4.8

• 0.7

21.7 Revenue 181.9 817.0 261.2 143.4 29.2 334.0 0.7 1,767.4 Current Operating Income 74.4 532.7 96.7 9.5 14.2 157.0 (37.2) 847.3 Share of net income from investments using equity method 3.9 Net Operating Profit After Equity Accounted Investments 851.2 Other operating (losses)/ gains (95.5) Profit Before Financial Items 755.7 Financial income 3.3 Finance costs (83.7) Profit Before Tax 675.3 Nine months ended 30 September 2019 In millions of US$ UK Norway Netherlands Germany North Africa Asia Pacific Corporate Total EBITDAX (including equity accounted affiliates) 110.6 633.0 148.4 39.2 21.2 252.5 7.2 1,212.1 Nine months ended 30 September 2018 In millions of US$ UK Norway Netherlands Germany North Africa Asia Pacific Corporate Total EBITDAX (including equity accounted affiliates) 127.4 698.7 174.9 48.7 23.6 295.8 (37.1) 1,332.0 As at 30 September 2019 In millions of US$ UK Norway Netherlands Germany North Africa Asia Pacific Corporate Total Balance Sheet Assets 1,083.3 2,361.6 736.7 546.4 659.9 1,212.1 207.2 6,807.2 Liabilities (289.2) (1,398.4) (922.1) (588.4) (12.7) (287.5) (1,550.9) (5,049.2) Net Assets 794.1 963.2 (185.4) (42.0) 647.2 924.6 (1,343.7) 1,758.0

Neptune Energy Group Midco Limited Unaudited Condensed Consolidated Financial Statements For the nine months ended 30 September 2019

Neptune Energy Group Midco Limited Report for the period ended 30 September 2019 28

4. Business combinations 4.1 Acquisition of ENGIE E&P International SA

During 2018, the Group finalised the fair values of the assets and liabilities of Engie E&P International SA which completed on 15 February

• 2018. All contingent consideration relating to the transaction was settled prior to the commencement of 2019.

4.2 Acquisition of VNG Norge AS

On 28 September 2018, the Group acquired 100 per cent of the voting shares of VNG Norge AS (an unlisted company based in Norway) from its parent VNG AG (a German natural gas and energy service provider). VNG Norge AS has a portfolio of 42 licences, five producing fields and three development projects including, in Norway: the Fenja oil development (30 per cent and operator), Bauge (2.5 per cent); and in Denmark: Solsort (13.8 per cent). The VNG Norge asset base is highly complementary to Neptune’s existing Norwegian portfolio. The fair values of the identifiable assets and liabilities of VNG Norge AS as at the date of acquisition were:

In millions of US$ Fair value recognised on acquisition Non-Current Assets Intangible assets 10.5 Property, plant and equipment 293.1 Deferred tax asset 117.1 Total Non-Current Assets 420.7 Current Assets Trade and other receivables 56.4 Inventories

• Cash and cash equivalents

71.2 Total Current-Assets 127.6 Total Assets 548.3 Non-Current Liabilities Provisions (112.4) Total Non-Current Liabilities (112.4) Current Liabilities Trade and other payables (1.2) Other current liabilities (80.0) Total Current Liabilities (81.2) Total Identifiable Net Assets At Fair Value 354.7 Goodwill arising on acquisition (provisional) 82.1 Purchase Consideration 436.8 Analysis Of Cash Flows On Consideration Net cash acquired with the subsidiary (including cash flows from investing activities) 71.2 Purchase consideration (436.8) Contingent consideration outstanding 24.3 Net Cash Flow On Acquisition (341.3)

Purchase consideration comprised cash of $412.5 million and contingent consideration of $24.3 million. The goodwill recognised arises principally as a result of recognition of deferred tax liabilities for the temporary difference between assigned fair values of oil and gas properties, which are based on post-tax values, and their tax base. The goodwill is not deductible for income tax purposes. Contingent Consideration Included in the purchase consideration at acquisition was $24.3 million which would be payable based upon satisfaction of certain tests linked to project success factors and milestones. No contingent consideration is payable if the tests are not achieved. The fair value of this contingent consideration was $22.3 million as at 30 September 2019 all the difference being due to currency translation adjustments between the two reporting dates. The possible outcome for contingent consideration ranges from $nil million to $50 million. The assigned fair values for the VNG business are now final.

Neptune Energy Group Midco Limited Unaudited Condensed Consolidated Financial Statements For the nine months ended 30 September 2019

Neptune Energy Group Midco Limited Report for the period ended 30 September 2019 29

5. Other operating (losses)/gains

In millions of US$ Nine months ended 30 September 2019 Nine months ended 30 September 2018 Mark-to-market on commodity contracts other than trading instruments 3.4 (27.6) Restructuring costs (68.0) 2.8 Business combination transaction costs

• (62.4)

Other (losses) / gains (17.8) (8.3) Total (82.4) (95.5)

6. 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:

In millions of US$ Nine months ended 30 September 2019 Nine months ended 30 September 2018 Current taxation 275.0 558.2 Deferred taxation 87.0 (35.4) Total Income tax expense recognised in income statement 362.0 522.8

The effective tax rate for the Group for 2019 was 81% (2018: 77%).

7. Intangible assets

In millions of US$ Exploration and evaluation Other Total Cost at 1 January 2019 80.3 37.6 117.9 Disposal (6.6)

• (6.6)

Additions 25.8 1.6 27.4 Unsuccessful exploration expenditure (0.4)

• (0.4)

Impairment (8.3)

• (8.3)

Transfers to property, plant and equipment (5.2)

• (5.2)

Currency translation adjustments (1.5) (1.8) (3.3) Cost at 30 September 2019 84.1 37.4 121.5 Amortisation at 1 January 2019

• (6.7)

(6.7) Charge for the year

• (6.6)

(6.6) Currency translation adjustments

• 0.5

0.5 Amortisation at 30 September 2019

• (12.8)

(12.8) Net book value at 30 September 2019 84.1 24.6 108.7 Net book value at 31 December 2018 80.3 30.9 111.2

8. Property, plant and equipment

In millions of US$ Oil and gas properties Other fixed assets Total Cost at 1 January 2019 4,520.2 33.4 4,553.6 IFRS 16 opening balance restatements 64.1 51.7 115.8 Disposal (5.5) (0.2) (5.7) Additions 569.6 0.7 570.3 Transfers from exploration and evaluation 4.9 0.3 5.2 Currency translation adjustments (164.8) (3.6) (168.4) Cost at 30 September 2019 4,988.5 82.3 5,070.8 Accumulated depreciation at 1 January 2019 (628.9) (2.5) (631.4) Charge for period (470.8) (9.7) (480.5) Impairment (4.8)

• (4.8)

Disposal 5.3 0.2 5.5 Currency translation adjustments 30.8 0.3 31.1 Accumulated depreciation at 30 September 2019 (1,068.4) (11.7) (1,080.1) Net book value at 30 September 2019 3,920.1 70.6 3,990.7 Net book value at 31 December 2018 3,891.3 30.9 3,922.2

Neptune Energy Group Midco Limited Unaudited Condensed Consolidated Financial Statements For the nine months ended 30 September 2019

Neptune Energy Group Midco Limited Report for the period ended 30 September 2019 30

9. Cash and cash equivalents

For the purposes of the condensed statement of cash flows, cash and cash equivalents comprise the following:

In millions of US$ 30 September 2019 31 December 2018 Cash at bank and in hand 151.0 191.1 Restricted cash 8.2 6.2 Total cash and cash equivalents 159.2 197.3

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 accruals

Trade payables are usually paid within 30 days of recognition. The carrying amount of financial assets and financial liabilities approximates their fair value. The finance lease liabilities are included within other current and non-current liabilities of $31.6 million and $105.0 million respectively.

In millions of US$ 30 September 2019 31 December 2018 Trade and other payables 154.4 94.5 Other current liabilities Lease liabilities 32.3

• Other

312.3 466.3 Current trade payables and accruals 499.0 560.8 Other non-current liabilities Lease liabilities 98.8

• Other

55.4 59.6 Non-Current trade payables and accruals 154.2 59.6 Total 653.2 620.4

• 11. Provisions

In millions of US$ 30 September 2019 31 December 2018 Current Restructuring 68.0 5.7 Post-employment benefit and other long term benefits 12.3

• Decommissioning

58.9 62.1 Other 3.6 1.5 Current Total 142.8 69.3 Non-Current Post-employment benefit and other long term benefits 206.7 232.5 Decommissioning 1,407.2 1,442.7 Non-Current Total 1,613.9 1,675.2 Total 1,756.7 1,744.5

Neptune Energy Group Midco Limited Unaudited Condensed Consolidated Financial Statements For the nine months ended 30 September 2019

Neptune Energy Group Midco Limited Report for the period ended 30 September 2019 31

• 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 30 June 2019 and 31 December 2018.

In millions of US$ 30 September 2019 31 December 2018

Financial assets at fair values

Commodity derivatives at fair value through profit and loss 4.0 3.4 Commodity derivatives in qualifying hedging relationships 115.7 69.9 Foreign forward exchange contracts at fair value through profit and loss 0.1

• Equity instruments designated at fair value through OCI

10.58% interest in Erdgas-Verkaufs-Gesellschaft mbH, Münster 18.7 19.7

Financial assets at amortised cost

Trade and other receivables 619.2 642.6 Tax receivable 43.4 83.7 Other non-current assets 29.2 8.8

Total

830.3 828.1

Total current

726.0 759.5

Total Non-current

104.3 68.6

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. Other non-current assets primarily comprises of joint venture lease receivables of $36.4m and other joint venture receivables of $11.5m 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. 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. Set out below is an overview of financial liabilities, other than cash and short-term deposits, held by the Group as at 30 September 2019. The Senior Notes held by the Group have a fair value of $565.8 million, compared to the carrying amount of $539.1 million. 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.

Neptune Energy Group Midco Limited Unaudited Condensed Consolidated Financial Statements For the nine months ended 30 September 2019

Neptune Energy Group Midco Limited Report for the period ended 30 September 2019 32 In millions of US$ 30 September 2019 31 December 2018

Financial liabilities at fair values

Commodity derivatives at fair value through profit and loss 4.8 14.1 Commodity derivatives in qualifying hedging relationships 57.1 76.3 Interest rate derivatives in qualifying hedging relationships 6.7 2.1 Foreign forward exchange contracts at fair value through profit and loss 11.1 12.2 Contingent consideration of the VNG Norge AS acquisition 22.3 24.3

Financial Liabilities amortised at cost

Trade and other payables 154.4 94.5 Income taxes payable 272.0 223.8 Other current liabilities 344.6 442.0 Other non-current liabilities 131.9 59.6 Short Term borrowings Society General facility 35.0

• Touat project finance facility

58.8

• Long Term borrowings

Reserve base lending facility 671.5 943.4 Senior Notes 539.1 537.7 Touat project finance facility 185.1 200.2 Subordinated Neptune Energy Group Limited loan 113.2 106.9

Total

2,607.6 2,737.1

Total current

847.8 822.5

Total Non-current

1,759.8 1,914.6

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 30 September 2019 and 31 December 2018. 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 levels during the period.

30 September 2019 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 30.09.2019 115.7 115.7

• Commodity derivatives at fair value through profit and loss

30.09.2019 4.0 4.0

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

30.09.2019 0.1 0.1

• Non-Listed equity Instruments

10.58% interest in Erdgas Münster GMBH 30.09.2019 18.7

• 18.7

Total 138.5 119.8 18.7

Neptune Energy Group Midco Limited Unaudited Condensed Consolidated Financial Statements For the nine months ended 30 September 2019

Neptune Energy Group Midco Limited Report for the period ended 30 September 2019 33 31 December 2018 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 31.12.2018 69.9 69.9

• Commodity derivatives at fair value through profit and loss

31.12.2018 3.4 3.4

• Non-Listed equity Instruments

10.58% interest in Erdgas Münster GMBH 31.12.2018 19.7

• 19.7

Total 93.0 73.3 19.7 30 September 2019 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 30.09.2019 57.1 57.1

• Commodity derivatives at fair value through profit and loss

30.09.2019 4.8 4.8

• Interest rate derivatives in qualifying hedging relationships

30.09.2019 6.7 6.7

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

30.09.2019 11.1 11.1

• Contingent consideration

22.3

• 22.3

Total 102.0 79.7 22.3 31 December 2018 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 31.12.2018 76.3 76.3

• Commodity derivatives at fair value through profit and loss

31.12.2018 14.1 14.1

• Interest rate derivatives in qualifying hedging relationships

31.12.2018 2.1 2.1

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

31.12.2018 12.2 12.2

• Contingent consideration

24.3

• 24.3

Total 129.0 104.7 24.3

12.2 Change in the value of Level 3 Instruments

The following table presents the changes in Level 3 instruments for the 9 months ended 30 September 2019.

In millions of US$ Equity investments Contingent consideration Total Opening balance at 31 December 2018 19.7 (24.3) (4.6) Gains recognised in other income *

• 2.0

2.0 Losses recognised in other comprehensive income (1.0)

• (1.0)

Closing balance at 30 September 2019

18.7 (22.3) (3.6)

* 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 $1 million change in valuation.

Neptune Energy Group Midco Limited Unaudited Condensed Consolidated Financial Statements For the nine months ended 30 September 2019

Neptune Energy Group Midco Limited Report for the period ended 30 September 2019 34

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.

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 2019

17.0 6.9 1.2

• 25.1

Add costs of hedging deferred and recognised in OCI (96.5) 3.9 (0.6) 7.0 (86.2) Less reclassified from OCI to profit or loss or included in finance costs 44.1 (9.8) (0.6)

• 33.7

Less deferred tax 10.4 1.0 (0.1)

• 11.3

At 30 September 2019

(25.0) 2.0 (0.1) 7.0 (16.1)

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 $million

Allotted, called up and fully paid

At 31 December 2018 1,977,175,201 1,977.2 Issued in the period

• At 30 September 2019

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. 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 2018 year end disclosure. Further details on contingencies can be found in Note 25 of the Neptune Energy Annual Report and Accounts 2018.

• 15. Related party transactions

There were no related party transactions in the nine months ended 30 September 2019.

• 16. Adoption of new accounting standards - financial impact of implementation of IFRS 16

Balance sheet The Group impact on the balance sheet of the implementation of IFRS16 has resulted in higher property, plant and equipment, current and non-current other assets and current and non-current lease liabilities.

In millions of US$ 30 September 2019 Property, plant and equipment Non-Current 103.4 Other Assets Non-Current 17.4 Current 8.5 Lease Liabilities Non-Current 98.8 Current 32.3

Neptune Energy Group Midco Limited Unaudited Condensed Consolidated Financial Statements For the nine months ended 30 September 2019

Neptune Energy Group Midco Limited Report for the period ended 30 September 2019 35

Income statement

The Group impact of the implementation of IFRS16 is a small increase in operating costs, along with a $5.2m increase in finance costs. The Group has recognised depreciation on right of use assets in the year to end of September 2019 of $13.5m. Interest on the Group’s finance lease liabilities for the year to the end of September 2019 was $5.1m, partly offset by interest on amounts due from joint venture partners

• f $1.6m. Other income of $2.4m has also be recognised reflecting reimbursements from partners.

The Group impact of the implementation of IFRS16 on EBITDAX ratio is a benefit of $14.3 million mainly reflecting a credit for reimbursements from partners.

Cash flow statement

Lease payments are now split between financing cash flows and operating cash flows in the cash flow statement. Financing cash flows represent repayment of principal, and operating cash flow payments of interest. In prior periods operating lease payments were all presented as operating cash flows under IAS 17. During the period to 30 September 2019, the Group has a total cash outflow of $15.4 million on qualifying leases.

• 17. Events after the reporting period

On 14 October 2019, the Group announced a conditional agreement with Energean Oil and Gas plc to acquire Edison E&P’s UK and Norwegian producing, development and exploration assets for an initial cash consideration of $250 million, to be adjusted for working capital (effective date January 1, 2019). A contingent consideration of up to $30 million may be paid by the end of 2026 if certain conditions are met. At completion, we will acquire the entire issued share capital of Edison E&P UK Ltd, Euroil Exploration Limited and Edison Norge AS. The purchase is contingent on Energean completing its proposed acquisition of Edison E&P. The acquisition will provide the Group with growth in contingent resources, an estimated 30 mmboe of 2P reserves and approximately 15 kboepd near term production in core areas of the North Sea, close to our existing infrastructure. On 25 October 2019, the Group via its wholly owned subsidiary Neptune Energy Bondco plc issued an aggregate principal amount of $300 million of 6⅝% senior notes due 2025 which represent an additional issuance of notes of the series of which an aggregate principal amount

• f $550 million were previously issued. As a result of the $300 million bond issue in October, which was used to partially repay drawn

commitments under our RBL. We currently have $1.5 billion undrawn under the RBL. When combined with our cash position of $159.2 million, we have headroom of $1.7 billion, providing sufficient funds to pursue growth opportunities.