Report for the THREE MONTHS ended 31 March 2021

Lundin Energy AB (publ) company registration number 556610-8055

Highlights

Record quarterly revenue of USD 1.1 billion with an achieved oil price of USD 61 per barrel
Strong free cash flow generation of MUSD 526, operating cost below guidance at USD 2.85 per boe and net debt reduced to below USD 3.5 billion
Dividend of USD 1.80 per share corresponding to MUSD 512 for the financial year 2020, approved by the 2021 AGM
Strong production performance of 183 Mboepd, above mid-point of guidance for the quarter
Johan Sverdrup Phase 1 production set to increase to 535 Mbopd ahead of schedule in May 2021
Key projects on track to deliver growth to over 200 Mboepd by 2023 and pipeline of new projects being matured to sustain production
Decarbonisation Strategy on track to achieve carbon neutrality from 2025 from operational emissions
World's first certified carbon neutrally produced crude oil sale

Financial summary

	1 Jan 2021- 31 Mar 2021 3 months	1 Jan 2020- 31 Mar 2020 3 months	1 Jan 2020- 31 Dec 2020 12 months
Production in Mboepd	182.9	152.4	164.5
Revenue and other income in MUSD	1,111.9	695.2	2,564.4
CFFO in MUSD	750.2	638.3	1,528.0
Per share in USD	2.64	2.25	5.38
EBITDAX in MUSD	1,018.4	581.1	2,140.2
Per share in USD	3.58	2.05	7.53
Free cash flow in MUSD	526.2	406.7	448.2
Per share in USD	1.85	1.43	1.58
Net result in MUSD	68.9	-310.6	384.2
Per share in USD	0.24	-1.09	1.35
Adjusted net result in MUSD	149.8	66.0	280.0
Per share in USD	0.53	0.23	0.99
Net debt in MUSD	3,464.0	3,694.2	3,911.5

Comment from Nick Walker, President and CEO of Lundin Energy:

"I am pleased to note that performance in the first quarter of 2021 has been about delivery on all fronts, which combined with the oil price recovery, yielded record financial results. And whilst the challenges of COVID-19 are still with us, we've continued to keep our main business activities on track.

"Our world class producing assets continue to outperform with excellent production efficiency, along with a strong HSE track record, driving our production for the quarter above the mid-point of the guidance range, whilst also maintaining our industry leading low operating costs.

"Johan Sverdrup continues to exceed expectations. Phase 1 production capacity is about to step-up to 535 Mbopd gross, and I expect, when the impact on the full field capacity has been assessed, we will see an increase above the current guidance of 720 Mbopd. Phase 2 of the project is progressing well with the offshore installation programme set to commence this quarter and remains on track for first oil in the fourth quarter of 2022.

"At the Greater Edvard Grieg Area, the projects that support the long-term plateau extension are on schedule, with the Edvard Grieg infill well programme underway and the Solveig and Rolvsnes projects set for first oil in the third quarter. I also see lot's more to come, with the new opportunities we are progressing in the area.

"With the projects we have underway we remain on target to deliver growth to over 200 Mboepd by 2023. I'm confident we can sustain at these levels with a pipeline of new projects that are being matured and an exciting exploration programme, targeting material resources.

"Financially we had a record quarter, with revenue of USD 1.1 billion, which delivered significant free cash flow of MUSD 526. This really shows the quality and resilience of our business, allowing us to fund growth, cover dividends and deleverage; reducing net debt to below USD 3.5 billion.

"We continue to make good progress decarbonising our operations, with everything in place to achieve carbon neutrality from 2025. Our recent commitment to the Karskruv wind farm in Sweden ensures that by end 2023, over 95 percent of our oil production will be powered by our own generated renewable energy. Leveraging our industry leading low emissions position, we recently announced the world's first certified, carbon neutrally produced crude oil sale, which I believe will be the first of many, and will become a key value differentiator for Lundin Energy.

"We've had a strong start to the year, making good progress on our key business priorities and looking forward, I remain confident that we can continue to deliver resilient, sustainable, growth into the future."

Lundin Energy is an experienced Nordic oil and gas company that explores for, develops and produces resources economically, efficiently and responsibly. We focus on value creation for our shareholders and wider stakeholders through three strategic pillars: Resilience, Sustainability and Growth. Our high quality, low cost assets mean we are resilient to oil price volatility, and our organic growth strategy, combined with our sustainable approach and commitment to decarbonisation, firmly establishes our leadership role in a lower carbon energy future. (Nasdaq Stockholm: LUNE). For more information, please visit us at www.lundin-energy.com or download our App www.myirapp.com/lundin

OPERATIONAL REVIEW

All the reported numbers and updates in the operational review relate to the three month period ending 31 March 2021 (reporting period), unless otherwise specified.

Ongoing COVID-19 Crisis

Lundin Energy has maintained a proactive approach in safeguarding the wellbeing of the Company's employees and contractors and ensuring the virus has minimal impact on its operations. To date there have been no disruptions to production due to the COVID-19 situation and while certain project activities have been affected, the disruptions have been successfully managed to avoid any negative impact on the production outlook.

Production

Production was 182.9 thousand barrels of oil equivalent per day (Mboepd), which was two percent above the mid-point of the production guidance range for the quarter. Strong facilities and reservoir performance has continued across the producing assets. Full year production guidance remains between 170 to 190 Mboepd.

Operating costs, net of tariff income, were USD 2.85 per boe, which was five percent below guidance for the quarter. Full year operating cost guidance remains USD 3 per boe.

Production in Mboepd	1 Jan 2021- 31 Mar 2021 3 months	1 Jan 2020- 31 Mar 2020 3 months	1 Jan 2020- 31 Dec 2020 12 months
Crude oil	170.0	140.7	152.7
Gas	12.9	11.7	11.8
Total production	182.9	152.4	164.5

Production in Mboepd	WI1	1 Jan 2021- 31 Mar 2021 3 months	1 Jan 2020- 31 Mar 2020 3 months	1 Jan 2020- 31 Dec 2020 12 months
Johan Sverdrup	20%	102.8	73.5	87.6
Edvard Grieg	65%	67.9	63.4	63.6
Ivar Aasen	1.385%	0.8	0.9	0.8
Alvheim Area	15% - 35%	11.4	14.6	12.5
		182.9	152.4	164.5

1 Lundin Energy's working interest (WI)

Production from Johan Sverdrup Phase 1 was in line with forecast, with a production efficiency of 98 percent. The Phase 1 processing capacity is planned to increase from 500 thousand barrels of oil per day (Mbopd) gross to 535 Mbopd in early May 2021, once the water injection system upgrades are completed, which are required to support the higher offtake rates. This represents a gross increase of 95 Mbopd since first oil in late 2019. Reservoir performance continues to be strong with high well productivities and excellent communication across the field. One production well was completed in the reporting period, with results in line with expectations and the field is currently producing from 13 wells. Johan Sverdrup is being operated with power supplied from shore and is one of the lowest CO2 emitting offshore fields in the world, with CO2 emissions of less than 0.1 kg per boe for the period. Operating costs were USD 1.66 per boe.

Production from the Edvard Grieg field was four percent ahead of forecast, benefitting from production efficiency of 99 percent, and higher available processing capacity due to the continued decline of the Ivar Aasen field. The planned three well infill drilling programme at Edvard Grieg commenced in January 2021 using the Rowan Viking jack-up rig, and is progressing according to schedule. Two of the infill wells will be equipped with the innovative 'Fishbones' completions, which will enhance productivity from the conglomeratic reservoir. The first of these wells has been successfully completed and is expected to be on stream in the second quarter of 2021. Power from shore at Edvard Grieg is expected to be online in late 2022 with the project progressing on schedule. The power cable has been installed on Edvard Grieg and laid on the seabed at Johan Sverdrup, awaiting arrival of the Phase 2 processing platform in 2022. The retirement of the existing gas turbine power generation system on the platform and installation of electric boilers to provide process heat, is on schedule and is expected to be operational in late 2022. Operating costs, net of tariff income, were USD 3.76 per boe.

Production from the Ivar Aasen field was five percent below forecast. The field water production rate has continued to increase, which has resulted in an accelerated oil production decline. Two infill wells have come on stream in the reporting period and both wells have performed below expectations.

Production from the Alvheim Area was in line with forecast with a production efficiency of 99 percent. One infill well that was spudded in late 2020 came on stream in March 2021, with results in line with expectations. Two infill wells are planned to be drilled in the Alvheim Area during the second half of 2021. Operating costs were USD 7.17 per boe.

Development

The development expenditure guidance for 2021 remains unchanged at MUSD 850.

Project	WI	Operator	Estimated gross reserves	Production start	Expected gross plateau production
Johan Sverdrup Phase 2	20%	Equinor	2.2 – 3.2 Bn boe1	Q4 2022	720 Mbopd1
Solveig Phase 1	65%	Lundin Energy	57 MMboe	Q3 2021	30 Mboepd
Rolvsnes EWT 2	80%	Lundin Energy	-	Q3 2021	3 Mboepd

1 Johan Sverdrup full field

2 Extended Well Test

Johan Sverdrup Phase 2

The Johan Sverdrup Phase 2 development project involves a second processing platform bridge linked to the Phase 1 field centre, subsea facilities to access the Avaldsnes, Kvitsøy and Geitungen satellite areas of the field, implementation of full field water alternating gas injection (WAG) for enhanced recovery and the drilling of 28 additional wells. The Johan Sverdrup gross field reserves are in the range 2.2 to 3.2 billion boe and the ambition of the partners in the field, is to achieve a recovery factor of more than 70 percent. Due to higher established processing capacity for Phase 1 of the development, the gross full field plateau, when Phase 2 comes on stream, will be at the increased level of 720 Mbopd. Study work to identify opportunities to increase the full field production capacity is ongoing and expected to be completed during the second quarter of 2021. The full field breakeven oil price for Johan Sverdrup, including past investments, is below USD 20 per boe.

The Phase 2 capital expenditure is estimated at gross NOK 41 billion (nominal), which is unchanged from the Phase 2 PDO estimate in 2019. The Jacket for the second processing platform has been completed and is awaiting installation offshore in the second quarter of 2021. The second processing platform topsides consists of three modules, the largest of which sailed from the construction yard in Thailand in April 2021 and will be assembled with the other two modules, when it arrives in Norway during the second quarter of 2021. The operation to install the second processing platform topsides on the jacket is planned for the spring of 2022. The new module on the existing Riser Platform will be installed in the third quarter of 2021 and the subsea facilities and flowlines installation will be completed during 2021. The disruptions to project activities due to COVID-19 have been effectively managed and first oil remains on schedule for the fourth quarter of 2022, with progress now over 55 percent complete.

Greater Edvard Grieg Area Tie-Back Projects

Solveig Phase 1 is the first Edvard Grieg subsea tie-back development and will contribute to keeping the Edvard Grieg platform on plateau production until the end of 2023. Phase 1 gross proved plus probable (2P) reserves are estimated at 57 MMboe and will be developed with three oil production wells and two water injection wells, achieving gross peak production of 30 Mboepd. The PDO for Solveig Phase 1 was approved in June 2019. The capital cost for the development is within the PDO estimate of MUSD 810 gross, with a breakeven oil price of below 20 USD per boe. Installation of the subsea facilities and flowlines is over 95 percent complete and development drilling is planned to commence in the second quarter of 2021. The project is on schedule for first oil in the third quarter of 2021, with progress now over 55 percent complete.

The Rolvsnes EWT project, which was approved by the authorities in July 2019, will be developed through a 3km subsea tie-back of the existing Rolvsnes horizontal well to the Edvard Grieg platform. The EWT will provide important reservoir data to support a decision on the potential Rolvsnes full field development. The project is being developed in conjunction with the Solveig project to take advantage of contracting and implementation synergies. In April 2021, completion activities on the existing Rolvsnes well commenced using the West Bollsta semi-submersible rig. The project is on schedule for first oil in the third quarter of 2021 and progress is now approximately 80 percent complete.

Exploration and Appraisal

The 2021 exploration and appraisal programme involves seven wells of which one has been drilled, yielding a small oil discovery at Segment D. The remaining six wells are targeting approximately 300 MMboe of gross unrisked prospective resources. The exploration and appraisal expenditure guidance for 2021 remains unchanged at MUSD 260.

Licence	Operator	WI	Well	Spud Date	Status
PL359	Lundin Energy	65%	Segment D	February 2021	Oil discovery
PL722	Equinor	20%	Shenzhou	April 2021	Ongoing
PL820S	MOL	41%	Iving	Second Quarter 2021
PL1671	Lundin Energy	40%	Lille Prinsen	Third Quarter 2021
PL981	Lundin Energy	60%	Merckx	Fourth Quarter 2021
PL976	Lundin Energy	50%	Dovregubben	Fourth Quarter 2021
PL10412	AkerBP	15%	Lyderhorn	Fourth Quarter 2021

2021 exploration and appraisal well programme

1 Lundin Energy's working interest in Licence PL167 will increase from 20% to 40% and operatorship will be transferred to Lundin Energy on closing of the transaction Equinor agreed in December 2020 2 Lundin Energy's working interest in Licence PL1041 will reduce from 30% to 15% on closing of the AkerBP transaction agreed in February 2021

In March 2021, the Segment D prospect, located north of the Solveig field on the Utsira High in the Norwegian North Sea in PL359, was drilled yielding an oil discovery. A 10 metre oil column was encountered in Triassic reservoir sandstones and the discovery is estimated to hold gross recoverable resources of 3 to 9 MMboe. A development will be evaluated in parallel with a potential future phase of development at Solveig.

In 2020, the Norwegian Government introduced temporary tax incentives aiming to increase activity on the Norwegian Continental Shelf, which applies to projects with PDO's submitted before the end of 2022. These tax incentives significantly improve project economics and the Company has taken steps to accelerate activities for nine potential projects, representing total net resources of approximately 200 MMboe, which could benefit from this opportunity. The Solveig Phase 2 project, incorporating the Segment D discovery and the Rolvsnes Full Field project, will be de-risked from production experience from Solveig Phase 1 and the Rolvsnes EWT. Appraisal drilling on the Iving and Lille Prinsen discoveries will commence in the second quarter and third quarter of 2021 respectively. Development studies for the Alvheim Area projects are progressing, with project sanctions for the Frosk and Kobra East/Gekko developments planned in mid-2021. In February 2021, the Company completed a licence swap with AkerBP, acquiring a six percent working interest in the Trell and Trine discoveries, which are potential tie-back developments to Alvheim, with concept studies ongoing towards possible sanction before the 2022 deadline. In the Barents Sea, development studies on Wisting are progressing well with concept selection planned in late 2021. Development feasibility studies on Alta are also progressing.

Decarbonisation

Decarbonisation is a key strategic pillar for Lundin Energy and a significant differentiator for the business. In January 2021, the decarbonisation strategy was accelerated by five years to achieve carbon neutrality for operational emissions from 2025. The strategy is composed of four pillars – reducing operational emissions, powering key assets from shore, investing in renewable power to replace net electricity usage and investments in nature-based carbon capture projects for any residual emissions. A critical step towards carbon neutrality will be the electrification of the Edvard Grieg platform, which will be executed in parallel with the Johan Sverdrup Phase 2 development, and will be operational in late 2022. Carbon emissions were 2.8 kg of CO2 per boe in the quarter, which is well within the Company's 2021 target of less than 4 kg of CO2 per boe. On completion of the electrification of Edvard Grieg the Company's average net carbon intensity is expected to be below 2 kg CO2 per boe, approximately one-tenth of the industry average.

In April 2021, the Company completed a transaction with OX2 AB (OX2) to acquire a 100 percent interest in the Karskruv onshore wind farm project in southern Sweden. The wind farm will become operational in late 2023 and will produce an estimated 290 GWh per annum, from 20 onshore wind turbines. The total investment in Karskruv, including the acquisition cost, will amount to MEUR 130 with the majority of the spend occurring in 2022 and 2023, and the project will be cash flow positive from 2024. Construction and commissioning of the second phase of the Leikanger hydropower project in Norway, was completed in March 2021 and is now operational at full capacity. Construction works are progressing well on the Metsälamminkangas (MLK) wind farm in Finland, with wind turbines and towers expected to be erected and commissioned in the second half of 2021 and with the project fully operational in 2022. The Company has now committed to three renewable projects, with a combined net power generation capacity of around 600 GWh per annum from late 2023, which will cover all of the Company's expected net electricity usage for the offshore producing assets. This means that from end 2023 over 95 percent of the Company's oil production will be powered by its own generated renewable energy.

In January 2021, the Company signed a partnership with Land Life Company B.V., to invest MUSD 35 in high quality re-forestation projects to plant approximately eight million trees between 2021 and 2025, capturing approximately 2.6 million tonnes of CO2 . Over time this project will be sufficient to naturally capture all of the Company's net residual emissions of CO2 , leading to carbon neutrality for operational emissions. During the reporting period the first planting of trees took place in Northern Spain.

The renewable expenditure guidance for 2021 is being increased from MUSD 70 to MUSD 100, reflecting the addition of the investment in the Karskruv wind farm project.

Certified Carbon Neutrally Produced Crude Oil Sale

In April 2021, Lundin Energy announced that it had sold a cargo of certified carbon neutrally produced Edvard Grieg crude to Saras S.p.A, the first such cargo in the world to have been traded and a significant step forward for the international oil market, in terms of a barrel of crude oil trading on the merits of its carbon emissions. Lundin Energy's Edvard Grieg field was the first oil field in the world to be independently certified by Intertek Group plc (Intertek), under its CarbonClearTM certification. The field is certified as low carbon at 3.8 kg of CO2 per boe, including exploration, development and production. In order to supply a fully carbon neutral barrel, residual emissions were compensated through a high quality, nature-based carbon capture project, certified by the Verified Carbon Standard (VCS) and independently certified by Intertek.

Decommissioning

The decommissioning expenditure guidance for 2021 remains unchanged at MUSD 20. The Brynhild field ceased production in 2018 and the decommissioning plan was approved by Norwegian and UK authorities in 2020. Abandonment of the four Brynhild subsea wells was completed in 2020 and removal of the subsea facilities is planned for the second quarter of 2021. The Gaupe field ceased production in 2018 and preparation of the decommissioning plan for the field is ongoing, with decommissioning activities expected to commence in 2023. Following completion of Brynhild and Gaupe decommissioning, the Company has no further planned decommissioning spend until around 2035.

Licence Awards and Transactions

In January 2021, the Company was awarded 19 licences in the 2020 APA licensing round, of which seven are as operator.

In February 2021, Lundin Energy entered into a sales and purchase agreement with AkerBP involving the acquisition of a six percent working interest in licences PL036E, PL036F, PL102H, PL102F, PL102D and PL102G which includes the Trell and Trine discoveries. The transaction included the sale of a five percent working interest in PL869 and a 15 percent working interest in PL1041. The transaction is subject to customary government approvals.

In February 2021, Lundin Energy applied for licences in the 25th licensing round where awards are anticipated in mid-2021. The Company currently holds 89 licences in Norway.

Health, Safety and Environment

During the reporting period, there were no lost time incidents and one medical treatment incident, resulting in a Lost Time Incident Rate of 0.0 per million hours worked and a Total Recordable Incident Rate of 1.6 per million hours worked. There were no process safety or material environmental incidents during the reporting period.

FINANCIAL REVIEW

Result

The Company generated record high quarterly revenue and other income of MUSD 1,111.9 (MUSD 695.2) resulting in operating profit for the reporting period of MUSD 764.9 (MUSD 404.2). The increase compared to the comparative period was mainly driven by higher sales volumes and higher oil prices. Sales volumes increased by 33 percent compared to the comparative period caused by better production performance, inventory movements and overlift movements during the reporting period. Operating profit was negatively impacted by higher exploration costs compared to the comparative period.

The net result for the reporting period amounted to MUSD 68.9 (MUSD -310.6), representing earnings per share of USD 0.24 (USD -1.09). Net result was impacted by a largely non-cash foreign currency exchange loss during the reporting period of MUSD 80.7 (MUSD 358.6). Adjusted net result for the reporting period amounted to MUSD 149.8 (MUSD 66.0), representing adjusted earnings per share of USD 0.53 (USD 0.23). Adjusted net result separates out the effects of accounting gains/losses from asset sales, loan modification gains, foreign currency exchange results, impairment charges and the tax impacts from these items and better reflects the net result generated by the Company's operational performance for the reporting period. Adjusted net result for the reporting period represented a record high quarterly adjusted net result for the Company.

The Company also generated record high quarterly earnings before interest, tax, depletion, amortization and exploration expenses (EBITDAX) for the reporting period of MUSD 1,018.4 (MUSD 581.1) representing EBITDAX per share of USD 3.58 (USD 2.05), with the increase compared to the comparative period mainly caused by the higher sales volumes and higher oil prices. Cash flow from operating activities (CFFO) for the reporting period amounted to MUSD 750.2 (MUSD 638.3), representing CFFO per share of USD 2.64 (USD 2.25) with the increase compared to the comparative period, again impacted by higher sales volumes and higher oil prices, but negatively impacted by working capital changes and higher tax payments during the reporting period. CFFO for the reporting period was again a quarterly record high for the Company. Free cash flow for the reporting period amounted to MUSD 526.2 (MUSD 406.7), representing free cash flow per share of USD 1.85 (USD 1.43), with the increase compared to the comparative period mainly impacted by higher CFFO.

Changes in the Group

There were no changes in the group during the reporting period.

Revenue and other income

Revenue and other income for the reporting period amounted to MUSD 1,111.9 (MUSD 695.2) and was comprised of net sales of oil and gas and other revenue as detailed in Note 1.

Net sales of oil and gas for the reporting period amounted to MUSD 1,106.9 (MUSD 685.5). The average price achieved by Lundin Energy for a barrel of oil equivalent (boe) from own production, amounted to USD 59.94 (USD 45.18) and is detailed in the following table. The average Dated Brent price for the reporting period amounted to USD 61.12 (USD 50.10) per barrel.

Net sales of oil and gas from own production for the reporting period are detailed in Note 3 and were comprised as follows:

Sales from own production Average price per boe expressed in USD	1 Jan 2021- 31 Mar 2021 3 months	1 Jan 2020- 31 Mar 2020 3 months	1 Jan 2020- 31 Dec 2020 12 months
Crude oil sales
- Quantity in Mboe	17,069.1	12,212.2	54,263.6
- Average price per bbl	61.10	47.96	39.96
Gas and NGL sales
- Quantity in Mboe	1,397.9	1,722.1	6,013.2
- Average price per boe	45.75	25.50	23.80
Total sales
- Quantity in Mboe	18,467.0	13,934.3	60,276.8
- Average price per boe	59.94	45.18	38.35

The table above excludes crude oil revenue from third party activities.

There were no sales of crude oil from third party activities during the reporting period, compared to MUSD 55.9 during the comparative period, consisting of crude oil purchased from outside the Group by Lundin Energy Marketing SA and sold to the market. Revenue from sale of oil and gas are recognised when control of the products is transferred to the customer.

Other income for the reporting period amounted to MUSD 5.0 (MUSD 9.7) and mainly included tariff income of MUSD 6.1 (MUSD 6.6), which is due to net income from Ivar Aasen tariffs paid to Edvard Grieg. Other income for the reporting period also included a loss of MUSD 2.7 (gain of MUSD 0.8) relating to oil price derivatives.

Production costs

Production costs including under/over lift movements and inventory movements for the reporting period amounted to MUSD 80.9 (MUSD 51.4) and are detailed in Note 2. The total production cost per barrel of oil equivalent produced is detailed in the table below:

	1 Jan 2021- 31 Mar 2021	1 Jan 2020- 31 Mar 2020	1 Jan 2020- 31 Dec 2020
Production costs	3 months	3 months	12 months
Cost of operations
- In MUSD	37.3	38.9	134.5
- In USD per boe	2.27	2.81	2.24
Tariff and transportation expenses
- In MUSD	15.7	12.4	50.7
- In USD per boe	0.95	0.89	0.84
Operating costs
- In MUSD	53.0	51.3	185.2
- In USD per boe1	3.22	3.70	3.08
Change in under/over lift position
- In MUSD	14.4	-1.3	-2.7
- In USD per boe	0.88	-0.10	-0.05
Change in inventory position
- In MUSD	11.8	-0.1	-11.2
- In USD per boe	0.72	-0.00	-0.19
Other
- In MUSD	1.7	1.5	5.9
- In USD per boe	0.10	0.11	0.10
Operating costs
- In MUSD	80.9	51.4	177.2
- In USD per boe	4.92	3.71	2.94

Note: USD per boe is calculated by dividing the cost by total production volume for the period.

1 The numbers in this table are excluding tariff income netting. Lundin Energy's operating cost for the reporting period of USD 3.22 (USD 3.70) per barrel is reduced to USD 2.85 (USD 3.22) when tariff income is netted off.

The total cost of operations for the reporting period amounted to MUSD 37.3 (MUSD 38.9) and the total cost of operations excluding operational projects amounted to MUSD 35.8 (MUSD 36.9).

The cost of operations per barrel for the reporting period amounted to USD 2.27 (USD 2.81) including operational projects and USD 2.18 (USD 2.67) excluding operational projects. The lower unit costs compared to the comparative period are mainly caused by higher production volumes partly offset by a stronger Norwegian Krone.

Tariff and transportation expenses for the reporting period amounted to MUSD 15.7 (MUSD 12.4) or USD 0.95 (USD 0.89) per boe. The increase on a per barrel basis compared to the comparative period is caused by a stronger Norwegian Krone.

Sales quantities in a period can differ from production quantities as a result of permanent and timing differences. Timing differences can arise due to under/over lift of entitlement, inventory, storage and pipeline balances effects. The change in under/over lift position is valued at production cost including depletion cost, and amounted to MUSD 14.4 (MUSD -1.3) in the reporting period due to the timing of the cargo liftings compared to production. The change in inventory position is also valued at production cost including depletion cost, and amounted to MUSD 11.8 (MUSD -0.1) in the reporting period due to a cargo in transit at the end of 2020 that was sold in early 2021. Sales quantities and production quantities are detailed in the table below:

Change in over/underlift position In Mboepd	1 Jan 2021- 31 Mar 2021 3 months	1 Jan 2020- 31 Mar 2020 3 months	1 Jan 2020- 31 Dec 2020 12 months
Production volumes	182.9	152.4	164.5
Inventory movements	7.0	–	-1.7
Production volumes including inventory movements	189.9	152.4	162.8
Sales volumes from own production	205.2	153.1	164.7
Change in over/underlift position	15.3	-0.7	-1.9

Other costs for the reporting period amounted to MUSD 1.7 (MUSD 1.5) and related to the business interruption insurance.

Depletion and decommissioning costs

Depletion and decommissioning costs for the reporting period amounted to MUSD 171.0 (MUSD 147.3), at an average rate of USD 10.38 (USD 10.62) per boe. The lower depletion costs on a per barrel basis compared to the comparative period is caused by a lower depletion rate per barrel in Norwegian Krone as a result of increased reserves in Norway. The depletion rate per boe is calculated in Norwegian Krone and with the Norwegian Krone having strengthened against the USD compared to the comparative period, the decrease in depletion rate per boe in USD is only two percent.

Exploration costs

Exploration costs expensed in the income statement for the reporting period amounted to MUSD 80.7 (MUSD 27.9). Exploration and appraisal costs are capitalised as they are incurred. When exploration and appraisal drilling is unsuccessful, the capitalised costs are expensed. All capitalised exploration costs are reviewed on a regular basis and are expensed when facts and circumstances suggest that the carrying value of an exploration and evaluation asset may exceed its recoverable amount.

Purchase of crude oil from third parties

There were no purchases of crude oil from third parties during the reporting period compared to MUSD 55.2 during the comparative period relating to crude oil purchased from outside the Group.

General, administrative and depreciation expenses

The general administrative and depreciation expenses for the reporting period amounted to MUSD 14.4 (MUSD 9.2), which included a charge of MUSD 1.5 (MUSD 0.6) in relation to the Group's long-term incentive plans (LTIP), see also Remuneration section on page 11. Fixed asset depreciation expenses for the reporting period amounted to MUSD 1.8 (MUSD 1.7).

Finance income

Finance income for the reporting period amounted to MUSD 0.5 (MUSD 0.6) and is detailed in Note 4.

Finance costs

Finance costs for the reporting period amounted to MUSD 119.2 (MUSD 416.7) and are detailed in Note 5.

The net foreign currency exchange loss for the reporting period amounted to MUSD 80.7 (MUSD 358.6). Foreign exchange movements occur on the settlement of transactions denominated in foreign currencies and the revaluation of working capital and loan balances to the prevailing exchange rate, at the balance sheet date where those monetary assets and liabilities are held in currencies other than the functional currencies of the Group's reporting entities. Lundin Energy is exposed to exchange rate fluctuations relating to the relationship between US Dollar and other currencies. Lundin Energy has entered into derivative financial instruments to address this exposure for exchange rate fluctuations for capital expenditure amounts and Corporate and Special Petroleum Tax amounts. For the reporting period, the net realised exchange gain on these settled foreign exchange instruments amounted to MUSD 8.7 (loss of MUSD 20.9).

The US Dollar strengthened four percent against the Euro during the reporting period, resulting in a net foreign currency exchange loss on the US Dollar denominated external loan, which is borrowed by a subsidiary using Euro as functional currency. In addition, the Norwegian Krone strengthened five percent against the Euro during the reporting period, generating a net foreign currency exchange gain on an intercompany loan balance denominated in Norwegian Krone.

Interest expenses for the reporting period amounted to MUSD 12.5 (MUSD 34.3) and represented the portion of interest charged to the income statement. An additional amount of interest of MUSD 5.2 (MUSD 5.3), associated with the funding of the Norwegian development projects was capitalised during the reporting period. The total interest expenses for the reporting period decreased compared to the comparative period as a result of a lower LIBOR rate, a lower interest rate margin over LIBOR following the refinancing in December 2020 and a lower average outstanding debt relative to the comparative period.

The result on interest rate hedge settlements for the reporting period amounted to a loss of MUSD 16.6 (MUSD 2.3), as a result of the lower LIBOR rate.

The amortisation of the deferred financing fees for the reporting period amounted to MUSD 2.3 (MUSD 3.9) and related to the expensing of the fees incurred in establishing the credit facility over the period of usage of the facility.

Loan facility commitment fees for the reporting period amounted to MUSD 1.8 (MUSD 2.5) and related to commitment fees for the undrawn amounts under the credit facility.

The unwinding of the loan modification gain in the comparative period amounted to MUSD 9.7 and related to the expensing of the accounting gain from the re-negotiated improved borrowing terms in 2018 for the reserve-based lending facility over the period of usage of the facility.

Share in result of joint ventures

Share in result of joint ventures for the reporting period amounted to MUSD -0.1 (MUSD –) and related to the 50 percent non-operated interest in the Leikanger hydropower project in Norway.

Tax

The overall tax charge for the reporting period amounted to MUSD 577.2 (MUSD 298.7) and is detailed in Note 6.

The current tax charge for the reporting period amounted to MUSD 507.0 (MUSD 260.5) and mainly related to Norway. The current tax charge for Norway for the reporting period related to both Corporate Tax and Special Petroleum Tax (SPT). The paid tax installments in Norway during the reporting period amounted to MUSD 121.0, which has in combination with the current tax charge for the reporting period and exchange rate movements resulted in an increase in current tax liabilities, compared to the end 2020, from MUSD 444.4 to MUSD 830.3.

On 19th June 2020, certain temporary changes in the Norwegian Petroleum Tax Law were enacted. The temporary changes allow investments incurred in 2020 and 2021 to be fully deducted against SPT in the year of investment compared to a six year linear depreciation for the ordinary tax regime. There is a further deduction available against the SPT in the form of an uplift. For the years 2020 and 2021, the uplift has been changed to 24 percent of the investment incurred in the year and is fully deductible in the year the investment is incurred, versus the previous uplift treatment which stipulated that the investment incurred during the year qualified for an uplift of 5.2 percent annually over four years (i.e. 20.8 percent uplift). The temporary changes in the Petroleum Tax Law also apply for Plan for Development and Operations submitted within 2022. These tax rules changes resulted in a reduction on current taxes for 2020 and 2021 and an increase in deferred taxes.

The deferred tax charge for the reporting period amounted to MUSD 70.2 (MUSD 38.2) and related to Norway. A deferred tax amount arises primarily where there is a difference in depletion for tax and accounting purposes, with the deferred tax charge increased for the reporting period due to the temporary tax changes for the Special Petroleum Tax in Norway, as outlined above.

The Group operates in various countries and fiscal regimes where corporate income tax rates are different from the regulations in Sweden. Corporate income tax rates for the Group vary between 13.7 and 78 percent. The effective tax rate for the reporting period is affected by items which do not receive a full tax credit such as the reported net foreign currency exchange results, Norwegian financial items and by the uplift allowance applicable in Norway for development expenditures against the offshore tax regime. The effective tax rate for the reporting period was mainly impacted by the reported foreign currency exchange loss and the effective tax rate on the adjusted net results for the reporting period amounted to 79 percent.

Balance Sheet

Non-current assets

Oil and gas properties amounted to MUSD 5,922.9 (MUSD 5,902.4) and are detailed in Note 7. Oil and gas properties included Right of use assets as per IFRS16 and amounted to MUSD 32.1 (MUSD –) relating to a drilling rig recognised under IFRS 16 during the reporting period.

Development, exploration and appraisal expenditure incurred for the reporting period was as follows:

Development expenditure In MUSD	1 Jan 2021- 31 Mar 2021 3 months	1 Jan 2020- 31 Mar 2020 3 months	1 Jan 2020- 31 Dec 2020 12 months
Norway	156.7	152.5	639.8
Development expenditure	156.7	152.5	639.8

Development expenditure of MUSD 156.7 (MUSD 152.5) was incurred in Norway during the reporting period, primarily on the Johan Sverdrup and Edvard Grieg fields. In addition an amount of MUSD 5.2 (MUSD 5.3) of interest was capitalised.

Exploration and appraisal expenditure	1 Jan 2021- 31 Mar 2021	1 Jan 2020- 31 Mar 2020	1 Jan 2020- 31 Dec 2020
In MUSD	3 months	3 months	12 months
Norway	64.7	43.3	152.9
Exploration and appraisal expenditure	64.7	43.3	152.9

Exploration and appraisal expenditure of MUSD 64.7 (MUSD 43.3) was incurred in Norway during the reporting period, primarily for the exploration and appraisal wells as summarised on page 4.

Other tangible fixed assets amounted to MUSD 43.3 (MUSD 45.2) and are detailed in Note 8. Other tangible fixed assets included Right of use assets as per IFRS 16 and amounted to MUSD 30.2 (MUSD 31.8).

Goodwill associated with the accounting for the Edvard Grieg transaction during 2016 amounted to MUSD 128.1 (MUSD 128.1).

Investments in joint ventures amounted to MUSD 113.1 (MUSD 110.6) and related to the 50 percent interest held by Lundin Energy in the Metsälamminkangas (MLK) wind farm project in Finland and the Leikanger hydropower project in Norway.

The net investments by the Company in the renewable energy business, mainly through its joint ventures, for the reporting period was at follows:

Renewables investments In MUSD	1 Jan 2021- 31 Mar 2021 3 months	1 Jan 2020- 31 Mar 2020 3 months	1 Jan 2020- 31 Dec 2020 12 months
MLK Windfarm – Finland	5.5	27.3	46.3
Leikanger Hydropower – Norway	0.6	–	49.8
Natural Carbon Capture	0.5	–	–
Renewables investments	6.6	27.3	96.1

Financial assets amounted to MUSD 13.6 (MUSD 13.5) and are detailed in Note 9. The sale of 2.6 percent of Johan Sverdrup during 2019 included a contingent consideration based on future reserve reclassifications and is due in 2026. This contingent consideration was fair valued by the Company and amounted to MUSD 12.8 (MUSD 12.7).

Trade and other receivables amounted to MUSD 17.3 (MUSD 17.3) and related to prepayments with a long-term nature.

Derivative instruments amounted to MUSD 11.9 (MUSD 3.8) and related to the marked-to-market gain on outstanding interest rate and currency hedge contracts, due to be settled after twelve months.

Current assets

Inventories amounted to MUSD 48.9 (MUSD 59.1) and included both well supplies and hydrocarbon inventories. Hydrocarbon inventories as per end 2020 included a cargo lifting at the end of 2020, which was sold in early 2021.

Trade and other receivables amounted to MUSD 441.5 (MUSD 278.6) and are detailed in Note 10. Trade receivables, which are all current, amounted to MUSD 254.6 (MUSD 215.5). Underlift amounted to MUSD 2.5 (MUSD 5.7) and was attributable to an underlift position on the producing fields, relating to oil from the Alvheim Area. Joint operations debtors relating to various joint venture receivables amounted to MUSD 21.9 (MUSD 21.8). Prepaid expenses and accrued income amounted to MUSD 156.0 (MUSD 26.5) and included MUSD 125.1 (MUSD –) related to cargo liftings during the reporting period not invoiced yet by the end of the quarter and prepaid operational and insurance expenditure. Other current assets amounted to MUSD 6.5 (MUSD 9.1).

Derivative instruments amounted to MUSD 2.0 (MUSD 12.1) and related to the marked-to-market gain on outstanding currency hedge contracts, due to be settled within twelve months.

Cash and cash equivalents amounted to MUSD 160.0 (MUSD 82.5). Cash balances are mainly held to meet ongoing operational funding requirements.

Non-current liabilities

Financial liabilities amounted to MUSD 3,619.0 (MUSD 3,983.9) and are detailed in Note 11. Bank loans amounted to MUSD 3,624.0 (MUSD 3,994.0) and related to the outstanding loan under the corporate credit facility. Capitalised financing fees relating to the establishment of the credit facility amounted to MUSD 34.4 (MUSD 37.1) and are being amortised over the expected life of the facility. The lease commitments amounted to MUSD 29.4 (MUSD 27.0) and related to the long-term portion of the lease commitments under IFRS 16. The short-term portion of the lease commitments was classified as current liabilities and amounted to MUSD 34.4 (MUSD 5.7). The increase in lease commitments is mainly caused by a drilling rig recognised under IFRS 16 during the reporting period.

Provisions amounted to MUSD 583.3 (MUSD 565.6) and are detailed in Note 12. The provision for site restoration amounted to MUSD 574.4 (MUSD 560.5) and related to the long-term portion of the future decommissioning obligations. The short-term portion of the future decommissioning obligations was classified as current liabilities and amounted to MUSD 15.5 (MUSD 16.0).

Deferred tax liabilities amounted to MUSD 2,966.6 (MUSD 2,893.9). The provision mainly arises on the excess of book value over the tax value of oil and gas properties. Deferred tax assets are netted off against deferred tax liabilities where they relate to the same jurisdiction.

Derivative instruments amounted to MUSD 72.6 (MUSD 144.7) and related to the marked-to-market loss on outstanding interest rate and currency hedge contracts, due to be settled after twelve months.

Current liabilities

Current financial liabilities amounted to MUSD 34.4 (MUSD 6.1) and are detailed in Note 11. Current financial liabilities related to the shortterm portion of the outstanding lease commitments.

Dividends amounted to MUSD 510.5 (MUSD 72.3) and related to the cash dividend approved by the AGM held on 30 March 2021 in Stockholm, paid in quarterly installments.

Trade and other payables amounted to MUSD 228.6 (MUSD 202.5) and are detailed in Note 13. Overlift amounted to MUSD 12.8 (MUSD 1.6) and was attributable to an overlift position on the producing fields, mainly relating to both oil and condensate from the Johan Sverdrup and Edvard Grieg fields. Joint operations creditors and accrued expenses amounted to MUSD 178.6 (MUSD 151.3) and related to activity in Norway. Other accrued expenses amounted to MUSD 23.6 (MUSD 31.7) and other current liabilities amounted to MUSD 6.0 (MUSD 9.2).

Derivative instruments amounted to MUSD 87.5 (MUSD 87.6) and related to the marked-to-market loss on outstanding interest rate and currency hedge contracts, due to be settled within twelve months.

Current tax liabilities amounted to MUSD 830.3 (MUSD 444.4) and related mainly to Norway. The current tax liabilities have increased during the reporting period mainly due to a current tax charge for the reporting period of MUSD 507.0 and cash taxes payments of MUSD 121.0 during the reporting period.

Current provisions amounted to MUSD 22.7 (MUSD 21.3) and are detailed in Note 12. The short-term portion of the future decommissioning obligations amounted to MUSD 15.5 (MUSD 16.0) mainly relating to the Brynhild field. The short-term portion of the provision for Lundin Energy's Unit Bonus Plan amounted to MUSD 7.2 (MUSD 5.3).

Changes in working capital

Changes in working capital for the reporting period, as included in the consolidated statement of cash flows, amounted to MUSD -134.5 (MUSD 141.2). Working capital increases mainly related to higher receivables at the end of the quarter, as a result of increasing oil prices and a cargo lifting schedule which was weighted more towards the second half of the quarter, partly offset by higher payables.

Parent Company

The business of the Parent Company is investment in and management of oil and gas assets and renewable energy projects. The net result for the Parent Company for the reporting period amounted to MSEK 4,402.1 (MSEK 2,815.6). The net result for the reporting period included MSEK 4,467.2 (MSEK 2,867.8) financial income as a result of received dividends from a subsidiary. The net result excluding received dividends amounted to MSEK -65.1 (MSEK -52.2).

The net result for the reporting period included general and administrative expenses of MSEK 75.9 (MSEK 64.0) and net finance income of MSEK 0.9 (MSEK 1.7) when excluding the received dividends as mentioned above.

Related Party Transactions

During the reporting period, the Group has not entered into any material transactions with related parties.

Liquidity

In December 2020, Lundin Energy entered into a five year corporate credit facility of USD 5.0 billion. The facility is a combination of a five-year USD 1.5 billion revolving credit facility and USD 3.5 billion term loans, split across two, three, four and five year maturities. The facility has a weighted average interest rate margin over LIBOR of 1.6 percent which is 0.9 percentage points lower compared to the previous financing. The facility also includes the option to bring in additional commitments in an accordion option of up to USD 1 billion. In line with the Company's best in class environmental profile, ESG KPIs on carbon intensity and renewable electricity generation have been incorporated into the margin structure, providing further financial incentives for the delivery of the Decarbonisation Strategy and the 2025 carbon neutrality target. The Company achieved a lower interest rate margin over LIBOR based on the ESG KPIs incorporated in the margin structure. The structure of the Facility is such, that it is compatible with unsecured bond issuances through the debt capital markets at pari passu terms, which could be utilized at an appropriate time to diversify the Company's capital structure.

The Company received on 29 July 2020 its inaugural public credit rating from S&P Global Rating, with a rating of BBB- with a stable outlook.

Contingent liabilities

The Swedish Prosecution Authority issued a notification of a corporate fine and forfeiture of economic benefits against Lundin Energy in relation to past operations in Sudan from 1997 to 2003. The notification indicated that the Prosecutor might seek a corporate fine of SEK 3 million and forfeiture of economic benefits from the alleged offense in the amount of SEK 3,282 million, based on the profit of the sale of the Block 5A asset in 2003 of SEK 720 million. Any potential corporate fine or forfeiture would only be imposed after the conclusion of a trial, should one occur. The investigation is in its eleventh year and Lundin Energy remains convinced that there are absolutely no grounds for any allegations of wrongdoing by any Company representative and the Company will firmly contest any corporate fine or forfeiture of economic benefits. The Company considers this to be a contingent liability and therefore no provision has been recognised.

Subsequent Events

Share Data

Lundin Energy AB's issued share capital amounted to SEK 3,478,713 represented by 285,924,614 shares with a quota value of SEK 0.01 each (rounded off) with the issued share capital including a bonus issue (sw. fondemission) of SEK 556,594 during 2019, to restore the share capital of Lundin Energy to the same amount as immediately prior to the share redemption as approved by the EGM of Lundin Energy held on 31 July 2019.

During 2017, Lundin Energy purchased 1,233,310 of its own shares at an average price of SEK 186.14 based on the approval granted at the AGM 2017. During 2018, Lundin Energy purchased an additional 640,000 of its own shares at an average price of SEK 186.77 based on the approval granted at the AGM 2017.

During 2020, Lundin Energy used 300,167 of the purchased own shares for settlement of the 2017 performance based incentive plan resulting in 1,573,143 of its own shares held by the Company by the end of the reporting period.

The AGM of Lundin Energy held on 30 March 2021 in Stockholm approved a cash dividend distribution for the year 2020 of USD 1.80 per share, to be paid in quarterly installments of USD 0.45 per share. Before payment, each quarterly dividend of USD 0.45 per share shall be converted into a SEK amount, and paid out in SEK, based on the USD to SEK exchange rate published by Sweden's central bank (Riksbanken) four business days prior to each record date (rounded off to the nearest whole SEK 0.01 per share). The final USD equivalent amount received by the shareholders may therefore slightly differ depending on what the USD to SEK exchange rate is on the date of the dividend payment. Based on the number of shares outstanding, excluding own shares held by the Company, the approved dividend distribution amounted to MSEK 4,467.2, equaling MUSD 511.8 based on the exchange rate on the date of AGM approval.

The first dividend payment was made on 8 April 2021. The second dividend payment is expected to be paid on 7 July 2021, with an expected record date of 2 July 2021 and expected ex-dividend date of 1 July 2021. The third dividend payment is expected to be paid on 7 October 2021, with an expected record date of 4 October 2021 and expected ex-dividend date of 1 October 2021. The fourth dividend payment is expected to be paid on 11 January 2022, with an expected record date of 5 January 2022 and expected ex-dividend date of 4 January 2022.

In order to comply with Swedish company law, a maximum total SEK amount shall be pre-determined to ensure that the dividend distributed does not exceed the available distributable reserves of the Company and such maximum amount for the 2020 dividend has been set to a cap of SEK 7.636 billion (i.e., SEK 1.909 billion per quarter). If the total dividend would exceed the cap of SEK 7.636 billion, the dividend will be automatically adjusted downwards so that the total dividend corresponds to the cap of SEK 7.636 billion.

Remuneration

Lundin Energy's principles for remuneration and details of the long-term incentive plans are provided in the Company's 2020 Annual Report, Remuneration Report and in the materials provided to shareholders in respect of the 2021 AGM, available on www.lundin-energy.com

Unit Bonus Plan

The number of units relating to the awards made in 2018, 2019 and 2020 under the Unit Bonus Plan outstanding as at 31 March 2021 were 68,766, 121,183 and 262,792 respectively.

Performance Based Incentive Plan

The AGM 2020 resolved a long-term performance based incentive plan in respect of Group management and a number of key employees. The plan is effective from 1 July 2020 and the 2020 award is accounted for from the second half of 2020. The total outstanding number of awards at 31 March 2021 was 411,897 and the awards vest over three years from 1 July 2020 subject to certain performance conditions being met. The outstanding number of awards has increased from the original number of awards reflecting dividends paid since the award date. Each original award was fair valued at the date of grant at SEK 147.10 using an option pricing model.

The 2019 plan is effective from 1 July 2019 and the total outstanding number of awards at 31 March 2021 was 332,728 and the awards vest over three years from 1 July 2019 subject to certain performance conditions being met. The outstanding number of awards has increased from the original number of awards reflecting dividends paid since the award date. Each original award was fair valued at the date of grant at SEK 169.00 using an option pricing model.

The 2018 plan is effective from 1 July 2018 and the total outstanding number of awards at 31 March 2021 was 260,055 and the awards vest over three years from 1 July 2018 subject to certain performance conditions being met. Each original award was fair valued at the date of grant at SEK 167.10 using an option pricing model. The dividend equivalent on vested shares is paid in cash at vesting.

Accounting Policies

This interim report has been prepared in accordance with International Accounting Standard (IAS) 34, Interim Financial Reporting, and the Swedish Annual Accounts Act (SFS 1995:1554).

The accounting policies adopted are in all aspects consistent with those followed in the preparation of the Group's annual financial statements for the year ended 31 December 2020.

The financial reporting of the Parent Company has been prepared in accordance with accounting principles generally accepted in Sweden, applying RFR 2 Reporting for legal entities, issued by the Swedish Financial Reporting Board and the Annual Accounts Act (SFS 1995:1554).

Under Swedish company regulations it is not allowed to report the Parent Company results in any other currency than Swedish Krona or Euro and consequently the Parent Company's financial information is reported in Swedish Krona and not the Group's presentation currency of US Dollar.

Risks and Risk Management

The objective of Business Risk Management is to identify, understand and manage threats and opportunities within the business on a continual basis. This objective is achieved by creating a mandate and commitment to risk management at all levels of the business. This approach actively addresses risk as an integral and continual part of decision making within the Group and is designed to ensure that all risks are identified, fully acknowledged, understood and communicated well in advance. The ability to manage and or mitigate these risks represents a key component in ensuring that the business aim of the Company is achieved. Nevertheless, oil and gas exploration, development and production involve high operational and financial risks, which even a combination of experience, knowledge and careful evaluation may not be able to fully eliminate or which are beyond the Company's control.

A detailed analysis of Lundin Energy's strategic, operational, financial and external risks and mitigation of those risks through risk management is described in Lundin Energy's 2020 Annual Report.

Ongoing COVID-19 Crisis

Derivative financial instruments

Lundin Energy has entered into derivative financial instruments to address its exposure for exchange rate fluctuations for capital expenditure amounts relating to its committed field development projects and Corporate and Special Petroleum Tax amounts. At 31 March 2021, Lundin Energy had outstanding foreign currency contracts as summarised below:

Buy	Sell	Average contractual Exchange rate	Settlement period
MNOK 2,443.7	MUSD 298.7	NOK 8.18:USD 1	Apr 2021 – Dec 2021
MNOK 1,430.0	MUSD 183.4	NOK 7.80:USD 1	Jan 2022 – Dec 2022
MNOK 530.0	MUSD 64.2	NOK 8.26:USD 1	Jan 2023 – Dec 2023
MNOK 300.0	MUSD 33.0	NOK 9.09:USD 1	Jan 2024 – Dec 2024

Lundin Energy entered into interest rate hedge contracts and at 31 March 2021 had outstanding interest rate hedge contracts as follows:

Borrowings expressed in MUSD	Fixing of floating LIBOR average rate per annum	Settlement period
3,100	2.28%	Apr 2021 – Dec 2021
3,200	2.20%	Jan 2022 – Dec 2022
2,700	1.38%	Jan 2023 – Dec 2023
2,200	1.47%	Jan 2024 – Dec 2024
1,400	0.71%	Jan 2025 – Dec 2025
1,100	0.81%	Jan 2026 – Jun 2026

Under IFRS 9, subject to hedge effectiveness testing, all of the hedges are treated as effective and changes to the fair value are reflected in other comprehensive income.

Exchange Rates

For the preparation of the financial statements for the reporting period, the following currency exchange rates have been used.

	31 Mar 2021			31 Mar 2020		31 Dec 2020
	Average	Period end	Average	Period end	Average	Period end
1 USD equals NOK	8.5140	8.5249	9.4887	10.5057	9.4146	8.5326
1 USD equals Euro	0.8295	0.8529	0.9072	0.9127	0.8762	0.8149
1 USD equals SEK	8.3933	8.7320	9.6765	10.0961	9.2092	8.1772

Consolidated Income Statement

	Note	1 Jan 2021- 31 Mar 2021	1 Jan 2020- 31 Mar 2020	1 Jan 2020- 31 Dec 2020
Expressed in MUSD		3 months	3 months	12 months
Revenue and other income	1
Revenue		1,106.9	685.5	2,533.2
Other income		5.0	9.7	31.2
		1,111.9	695.2	2,564.4
Cost of sales
Production costs	2	-80.9	-51.4	-177.2
Depletion and decommissioning costs		-171.0	-147.3	-607.7
Exploration costs		-80.7	-27.9	-104.9
Purchase of crude oil from third parties		–	-55.2	-217.8
Gross profit	3	779.3	413.4	1,456.8
General, administration and depreciation expenses		-14.4	-9.2	-36.1
Operating profit		764.9	404.2	1,420.7
Net financial items
Finance income	4	0.5	0.6	172.3
Finance costs	5	-119.2	-416.7	-318.6
		-118.7	-416.1	-146.3
Share in result of joint ventures		-0.1	–	-0.1
Profit before tax		646.1	-11.9	1,274.3
Income tax	6	-577.2	-298.7	-890.1
Net result		68.9	-310.6	384.2
Attributable to:
Shareholders of the Parent Company		68.9	-310.6	384.2
Non-controlling interest		–	–	–
		68.9	-310.6	384.2
Earnings per share – USD		0.24	-1.09	1.35
Earnings per share fully diluted – USD		0.24	-1.09	1.35
Adjusted earnings per share – USD		0.53	0.23	0.99
Adjusted earnings per share fully diluted – USD		0.53	0.23	0.98

Consolidated Statement of Comprehensive Income

Expressed in MUSD	1 Jan 2021- 31 Mar 2021 3 months	1 Jan 2020- 31 Mar 2020 3 months	1 Jan 2020- 31 Dec 2020 12 months
Net result	68.9	-310.6	384.2

Items that may be subsequently reclassified to profit or loss:
Exchange differences foreign operations	100.0	1.1	-210.1
Cash flow hedges	57.7	-384.4	-63.4
Other comprehensive income, net of tax	157.7	-383.3	-273.5

Total comprehensive income	226.6	-693.9	110.7
Attributable to:
Shareholders of the Parent Company	226.6	-693.9	110.7
Non-controlling interest	–	–	–
	226.6	-693.9	110.7

Consolidated Balance Sheet

Expressed in MUSD	Note	31 March 2021	31 December 2020
ASSETS
Non-current assets
Oil and gas properties	7	5,922.9	5,902.4
Other tangible fixed assets	8	43.3	45.2
Goodwill		128.1	128.1
Investments in joint ventures		113.1	110.6
Financial assets	9	13.6	13.5
Trade and other receivables	10	17.3	17.3
Derivative instruments	14	11.9	3.8
Total non-current assets		6,250.2	6,220.9
Current assets
Inventories		48.9	59.1
Trade and other receivables	10	441.5	278.6
Derivative instruments	14	2.0	12.1
Cash and cash equivalents		160.0	82.5
Total current assets		652.4	432.3
TOTAL ASSETS		6,902.6	6,653.2
EQUITY AND LIABILITIES
Equity
Shareholders´ equity		-2.052.9	-1,769.1
Liabilities
Non-current liabilities
Financial liabilities	11	3,619.0	3,983.9
Provisions	12	583.3	565.6
Deferred tax liabilities		2,966.6	2,893.9
Derivative instruments	14	72.6	144.7
Total non-current liabilities		7,241.5	7,588.1
Current liabilities
Financial liabilities	11	34.4	6.1
Dividends		510.5	72.3
Trade and other payables	13	228.6	202.5
Derivative instruments	14	87.5	87.6
Current tax liabilities		830.3	444.4
Provisions	12	22.7	21.3
Total current liabilities		1,714.0	834.2
Total liabilities		8,955.5	8,422.3
TOTAL EQUITY AND LIABILITIES		6,902.6	6,653.2

Consolidated Statement of Cash Flows

	1 Jan 2021- 31 Mar 2021	1 Jan 2020- 31 Mar 2020	1 Jan 2020- 31 Dec 2020
Expressed in MUSD	3 months	3 months	12 months
Cash flows from operating activities
Net result	68.9	-310.6	384.2
Adjustments for:
Exploration costs	80.7	27.9	104.9
Depletion, depreciation and amortisation	172.8	149.0	614.6
Current tax	507.0	260.5	511.8
Deferred tax	70.2	38.2	378.3
Long-term incentive plans	4.8	-0.1	9.5
Foreign currency exchange gain/ loss	84.8	337.7	-230.3
Interest expense	12.5	34.3	104.3
Unwinding of loan modification gain	–	9.7	99.7
Amortisation of deferred financing fees	2.3	3.9	37.6
Other	18.6	3.8	6.3
Interest received	0.4	0.3	0.8
Interest paid	-17.3	-39.5	-126.6
Income taxes paid / received	-121.0	-18.0	-428.5
Changes in working capital	-134.5	141.2	61.4
Total cash flows from operating activities	750.2	638.3	1,528.0
Cash flows from investing activities
Investment in oil and gas properties	-218.4	-195.8	-919.7
Investment in renewable energy business1	-5.2	-32.3	-99.8
Investment in other fixed assets	-0.3	-1.2	-2.4
Decommissioning costs paid	-0.1	-2.3	-57.9
Total cash flows from investing activities	-224.0	-231.6	-1,079.8
Cash flows from financing activities
Net drawdown/repayment of corporate credit facility	-370.0	–	3,994.0
Net drawdown/repayment of reserve-based lending facility	–	-308.0	-4,092.0
Repayment of principal portion of lease commitments	-4.0	-0.8	-3.2
Financing fees paid	-2.6	-0.6	-36.8
Dividends paid	-71.1	-105.1	-318.2
Total cash flows from financing activities	-447.7	-414.5	-456.2

Change in cash and cash equivalents	78.5	-7.8	-8.0
Cash and cash equivalents at the beginning of the period	82.5	85.3	85.3
Currency exchange difference in cash and cash equivalents	-1.0	12.3	5.2
Cash and cash equivalents at the end of the period	160.0	89.8	82.5

1 Includes incurred cost relating to the acquisition of the renewable energy business and working capital funding

Consolidated Statement of Changes in Equity

Expressed in MUSD	Share capital	Additional paid-in capital / Other reserves	Retained earnings	Dividends	Total equity
At 1 January 2020	0.5	-169.7	-1,429.6	–	-1,598.8

Comprehensive income
Net result	–	–	-310.6	–	-310.6
Other comprehensive income	–	-383.3	–	–	-383.3
Total comprehensive income	–	-383.3	-310.6	–	-693.9
Transactions with owners
Distributions	–	–	–	-284.1	-284.1
Value of employee services	–	–	1.3	–	1.3
Total transaction with owners	–	–	1.3	-284.1	-282.8
At 31 March 2020	0.5	-553.0	-1,738.9	-284.1	-2,575.5
Comprehensive income
Net result	–	–	694.8	–	694.8
Other comprehensive income	–	109.8	–	–	109.8
Total comprehensive income	–	109.8	694.8	–	804.6
Transactions with owners
Issuance of treasury shares	–	7.3	–	–	7.3
Share based payments	–	-9.6	–	–	-9.6
Value of employee services	–	–	4.1	–	4.1
Total transaction with owners	–	-2.3	4.1	–	1.8

At 31 December 2020	0.5	-445.5	-1,040.0	-284.1	-1,769.1
Transfer of prior year dividends	–	–	-284.1	284.1	–
Comprehensive income
Net result	–	–	68.9	–	68.9
Other comprehensive income	–	157.7	–	–	157.7
Total comprehensive income	–	157.7	68.9	–	226.6

Transactions with owners
Distributions	–	–	–	-511.8	-511.8
Value of employee services	–	–	1.4	–	1.4
Total transaction with owners	–	–	1.4	-511.8	-510.4
At 31 March 2021	0.5	-287.8	-1,253.8	-511.8	-2,052.9

Note 1 – Revenue and other income MUSD	1 Jan 2021- 31 Mar 2021 3 months	1 Jan 2020- 31 Mar 2020 3 months	1 Jan 2020- 31 Dec 2020 12 months
Revenue
Crude oil from own production	1,043.0	585.7	2,168.5
Crude oil from third party activities	–	55.9	221.5
Condensate	18.9	23.0	63.8
Gas	45.0	20.9	79.4
Sales of oil and gas	1,106.9	685.5	2,533.2

Other income	5.0	9.7	31.2
Revenue and other income	1,111.9	695.2	2,564.4

Note 2 – Production costs MUSD	1 Jan 2021- 31 Mar 2021 3 months	1 Jan 2020- 31 Mar 2020 3 months	1 Jan 2020- 31 Dec 2020 12 months
Cost of operations	37.3	38.9	134.5
Tariff and transportation expenses	15.7	12.4	50.7
Change in under/over lift position	14.4	-1.3	-2.7
Change in inventory position	11.8	-0.1	-11.2
Other	1.7	1.5	5.9
Production costs	80.9	51.4	177.2

Note 3 – Segment information MUSD	1 Jan 2021- 31 Mar 2021 3 months	1 Jan 2020- 31 Mar 2020 3 months	1 Jan 2020- 31 Dec 2020 12 months
Norway
Crude oil from own production	1,043.0	585.7	2,168.5
Condensate	18.9	23.0	63.8
Gas	45.0	20.9	79.4
Revenue	1,106.9	629.6	2,311.7
Other income	5.0	8.9	30.3
Revenue and other income	1,111.9	638.5	2,342.0
Production costs	-80.9	-51.4	-177.2
Depletion and decommissioning costs	-171.0	-147.3	-607.7
Exploration costs	-80.7	-27.9	-104.9
Gross profit	779.3	411.9	1,452.2
Other
Crude oil from third party activities	–	55.9	221.5
Revenue	–	55.9	221.5
Other income	–	0.8	0.9
Revenue and other income	–	56.7	222.4
Purchase of crude oil from third parties	–	-55.2	-217.8
Gross profit	–	1.5	4.6

Note 3 – Segment information cont. MUSD	1 Jan 2021- 31 Mar 2021 3 months	1 Jan 2020- 31 Mar 2020 3 months	1 Jan 2020- 31 Dec 2020 12 months
Total
Crude oil from own production	1,043.0	585.7	2,168.5
Crude oil from third party activities	–	55.9	221.5
Condensate	18.9	23.0	63.8
Gas	45.0	20.9	79.4
Revenue	1,106.9	685.5	2,533.2
Other income	5.0	9.7	31.2
Revenue and other income	1,111.9	695.2	2,564.4
Production costs	-80.9	-51.4	-177.2
Depletion and decommissioning costs	-171.0	-147.3	-607.7
Exploration costs	-80.7	-27.9	-104.9
Purchase of crude oil from third parties	–	-55.2	-217.8
Gross profit	779.3	413.4	1,456.8

Note 4 – Finance income MUSD	1 Jan 2021- 31 Mar 2021 3 months	1 Jan 2020- 31 Mar 2020 3 months	1 Jan 2020- 31 Dec 2020 12 months
Foreign currency exchange gain, net	–	–	171.0
Interest income	0.5	0.6	1.3
Finance income	0.5	0.6	172.3

Note 5 – Finance costs MUSD	1 Jan 2021- 31 Mar 2021 3 months	1 Jan 2020- 31 Mar 2020 3 months	1 Jan 2020- 31 Dec 2020 12 months
Foreign currency exchange loss, net	80.7	358.6	–
Interest expense	12.5	34.3	104.4
Loss on interest rate hedge settlement	16.6	2.3	44.5
Unwinding of site restoration discount	5.0	4.7	19.2
Amortisation of deferred financing fees	2.3	3.9	37.6
Loan facility commitment fees	1.8	2.5	11.5
Unwinding of loan modification gain	–	9.7	99.7
Other	0.3	0.7	1.7
Finance costs	119.2	416.7	318.6

Note 6 – Income tax MUSD	1 Jan 2021- 31 Mar 2021 3 months	1 Jan 2020- 31 Mar 2020 3 months	1 Jan 2020- 31 Dec 2020 12 months
Current tax	507.0	260.5	511.8
Deferred tax	70.2	38.2	378.3
Finance income	577.2	298.7	890.1

Note 7 – Oil and gas properties MUSD	31 March 2021	31 December 2020
Right of use assets	32.1	–
Producing assets	3,661.2	3,776.9
Assets under development	1,350.4	1,216.1
Capitalised exploration and appraisal expenditure	879.2	909.4
	5,922.9	5,902.4

Note 8 – Other tangible fixed assets MUSD	31 March 2021	31 December 2020
Right of use assets	30.2	31.8
Other	13.1	13.4
	43.3	45.2

Note 9 – Financial assets MUSD	31 March 2021	31 December 2020
Contingent consideration	12.8	12.7
Associated companies	0.3	0.3
Other	0.5	0.5
	13.6	13.5

Note 10 – Trade and other receivables MUSD	31 March 2021	31 December 2020
Non-current:
Prepaid expenses and accrued income	17.3	17.3
	17.3	17.3
Current:
Trade receivables	254.6	215.5
Underlift	2.5	5.7
Joint operations debtors	21.9	21.8
Prepaid expenses and accrued income	156.0	26.5
Other	6.5	9.1
	441.5	278.6

	458.8	295.9

Note 11 – Financial liabilities MUSD	31 March 2021	31 December 2020
Non-current:
Bank loans	3,624.0	3,994.0
Capitalised financing fees	-34.4	-37.1
Lease commitments	29.4	27.0
	3,619.0	3,983.9
Current:
Lease commitments	34.4	5.7
Others	–	0.4
	34.4	6.1
	3,653.4	3,990.0

Note 12 – Provisions MUSD	31 March 2021	31 December 2020
Non-current:
Site restoration	574.4	560.5
Long-term incentive plans	3.6	2.3
Other	5.3	2.8
	583.3	565.6
Current:
Site restoration	15.5	16.0
Long-term incentive plans	7.2	5.3
	22.7	21.3
	606.0	586.9

Note 13 – Trade and other payables MUSD	31 March 2021	31 December 2020
Trade payables	7.6	8.7
Overlift	12.8	1.6
Joint operations creditors and accrued expenses	178.6	151.3
Other accrued expenses	23.6	31.7
Other	6.0	9.2
	228.6	202.5

Note 14 – Financial Instruments

For financial instruments measured at fair value in the balance sheet, the following fair value measurement hierarchy is used:

– Level 1: based on quoted prices in active markets;

– Level 2: based on inputs other than quoted prices as within level 1, that are either directly or indirectly observable;

– Level 3: based on inputs which are not based on observable market data.

Based on this hierarchy, financial instruments measured at fair value can be detailed as follows:

31 March 2021 MUSD	Level 1	Level 2	Level 3
Assets
Contingent consideration	–	–	12.8
Derivative instruments – non-current	–	11.9	–
Derivative instruments – current	–	2.0	–
	–	13.9	12.8
Liabilities
Derivative instruments – non-current	–	72.6	–
Derivative instruments – current	–	87.5	–
	–	160.1	–

31 December 2020 MUSD	Level 1	Level 2	Level 3
Assets
Contingent consideration	–	–	12.7
Derivative instruments – non-current	–	3.8	–
Derivative instruments – current	–	12.1	–
	–	15.9	12.7
Liabilities
Derivative instruments – non-current	–	144.7	–
Derivative instruments – current	–	87.6	–
	–	232.3	–

There were no transfers between the levels during the reporting period.

The fair value of the financial assets is estimated to equal the carrying value. The fair value of the derivative instruments is calculated using the forward interest rate curve and the forward exchange rate curve respectively for the interest rate swap and the currency hedging contracts. The hedge counterparties are all banks which are party to the loan facility agreement. The sale of 2.6 percent of Johan Sverdrup during 2019 included a contingent consideration based on future reserve reclassifications and is due in 2026, This contingent consideration was fair valued by the Company in 2019 with no changes in subsequent years.

Note 15 – Additional disclosures

Additional disclosures supplementing the financial statements are included in the Financial Review section of this report on pages 6-12.

Parent Company Income Statement

	1 Jan 2021- 31 Mar 2021	1 Jan 2020- 31 Mar 2020	1 Jan 2020- 31 Dec 2020
Expressed in MSEK	3 months	3 months	12 months
Revenue	9.9	10.1	19.5

General and administration expenses	-75.9	-64.0	-240.1
Operating loss	-66.0	-53.9	-220.6

Net financial items
Finance income	4,468.1	2,869.6	2,867.8
Finance costs	–	-0.1	-5.3
	4,468.1	2,869.5	2,862.5

Profit before tax	4,402.1	2,815.6	2,641.9

Income tax	–	–	–

Net result	4,402.1	2,815.6	2,641.9

Parent Company Comprehensive Income Statement

	1 Jan 2021- 31 Mar 2021	1 Jan 2020- 31 Mar 2020	1 Jan 2020- 31 Dec 2020
Expressed in MSEK	3 months	3 months	12 months
Net result	4,402.1	2,815.6	2,641.9

Other comprehensive income	–	–	–

Total comprehensive income	4,402.1	2,815.6	2,641.9
Attributable to:
Shareholders of the Parent Company	4,402.1	2,815.6	2,641.9
	4,402.1	2,815.6	2,641.9

Parent Company Balance Sheet

Expressed in MSEK	31 March 2021	31 December 2020
ASSETS
Non-current assets
Shares in subsidiaries	55,118.9	55,118.9
Other tangible fixed assets	0.4	0.5
Total non-current assets	55,119.3	55,119.4
Current assets:
Receivables	4,352.8	568.5
Cash and cash equivalents	39.4	26.6
Total current assets	4,392.2	595.1
TOTAL ASSETS	59,511.5	55,714.5
SHAREHOLDERS´EQUITY AND LIABILITIES
Shareholders´ equity including net result for the period	55,014.9	55,080.0
Non-current liabilities
Provisions	1.5	0.9
Total non-current liabilities	1.5	0.9
Current liabilities
Dividends	4,458.2	591.5
Other liabilities	36.9	42.1
Total current liabilities	4,495.1	633.6
Total liabilities	4,496.6	634.5
TOTAL EQUITY AND LIABILITIES	59,511.5	55,714.5

Parent Company Cash Flow Statement

	1 Jan 2021-	1 Jan 2020-	1 Jan 2020-
Expressed in MSEK	31 Mar 2021 3 months	31 Mar 2020 3 months	31 Dec 2020 12 months
Cash flow from operations
Net result	4,402.1	2,815.6	2,641.9

Adjustment for non-cash related items	-4,467.6	-2,870.1	-711.0
Changes in working capital	668.6	1,039.6	1,007.3
Total cash flow from operations	603.1	985.1	2,938.2

Cash flow from investing
Investments in other fixed assets	–	–	-0.2
Total cash flow from investing	–	–	-0.2
Cash flow from financing

Dividends paid	-591.5	-985.7	-3,003.1
Issuance of treasury shares	–	–	63.1
Total cash flow from financing	-591.5	-985.7	-2,940.0

Change in cash and cash equivalents	11.6	-0.6	-2.0
Cash and cash equivalents at the beginning of the period	26.6	31.7	31.7
Currency exchange difference in cash and cash equivalents	1.2	1.7	-3.1
Cash and cash equivalents at the end of the period	39.4	32.8	26.6

Parent Company Statement of Changes in Equity

		Restricted equity	Unrestricted equity
	Share	Statutory	Other	Retained
Expressed in MSEK	capital	reserve	reserves	earnings	Dividends	Total	Total equity
Balance at 1 January 2020	3.5	861.3	6,479.7	47,898.3	–	54,378.0	55,242.8
Total comprehensive income	–	–	–	2,815.6	–	2,815.6	2,815.6
Transactions with owners
Distributions	–	–	–	–	-2,867.8	-2,867.8	-2,867.8
Total transactions with owners	–	–	–	–	-2,867.8	-2,867.8	-2,867.8
Balance at 31 March 2020	3.5	861.3	6,479.7	50,713.9	-2,867.8	54,325.8	55,190.6
Total comprehensive income	–	–	–	-173.7	–	-173.7	-173.7
Transactions with owners
Issuance of treasury shares	–	–	63.1	–	–	63.1	63.1
Total transactions with owners	–	–	63.1	–	–	63.1	63.1
Balance at 31 December 2020	3.5	861.3	6,542.8	50.540.2	-2,867.8	54,215.2	55,080.0
Transfer of prior year dividends	–	–	–	-2,867.8	2,867.8	–	–
Total comprehensive income	–	–	–	4,402.1	–	4,402.1	4,402.1
Transactions with owners
Distributions	–	–	–	–	-4,467.2	-4,467.2	-4,467.2
Total transactions with owners	–	–	–	–	-4,467.2	-4,467.2	-4,467.2
Balance at 31 March 2021	3.5	861.3	6,542.8	52,074.5	-4.467.2	54,150.1	55,014.9

Key Financial Data

Lundin Energy discloses alternative performance measures as part of its financial statements prepared in accordance with ESMA's (European Securities and Markets Authority) guidelines. Lundin Energy believes that the alternative performance measures provide useful supplement information to management, investors, security analysts and other stakeholders and are meant to provide an enhanced insight into the financial development of Lundin Energy's business operations and to improve comparability between periods. Reconciliations of relevant alternative performance measures are provided on the following page. Definitions of the performance measures are provided under the key ratio definitions below:

Financial data MUSD	1 Jan 2021- 31 Mar 2021 3 months	1 Jan 2020- 31 Mar 2020 3 months	1 Jan 2020- 31 Dec 2020 12 months
Revenue and other income	1,111.9	695.2	2,564.4
Operating cash flow	524.0	328.1	1,657.6
CFFO	750.2	638.3	1,528.0
EBITDAX	1,018.4	581.1	2,140.2
Free cash flow	526.2	406.7	448.2
Net result	68.9	-310.6	384.2
Adjusted net result	149.8	66.0	280.0
Net debt	3,464.0	3,694.2	3,911.5
Data per share USD
Shareholders' equity per share	-7.22	-9.07	-6.22
Operating cash flow per share	1.84	1.16	5.83
CFFO per share	2.64	2.25	5.38
EBITDAX per share	3.58	2.05	7.53
Free cash flow per share	1.85	1.43	1.58
Earnings per share	0.24	-1.09	1.35
Earnings per share fully diluted	0.24	-1.09	1.35
Adjusted earnings per share	0.53	0.23	0.99
Adjusted earnings per share fully diluted	0.53	0.23	0.98
Dividend per share1	0.25	0.37	1.12
Number of shares issued at period end	285,924,614	285,924,614	285,924,614
Number of shares in circulation at period end	284,351,471	284,051,304	284,351,471
Weighted average number of shares for the period	284,351,471	284,051,304	284,177,604
Weighted average number of shares for the period fully diluted	284,886,920	284,609,911	284,830,491
Share price
Share price at period end in SEK	274.40	190.50	222.30
Share price at period end in USD2	31.42	18.87	27.19
Key ratios
Return on equity (%)3	–	–	–
Return on capital employed (%)	14	8	22
Net debt/equity ratio (%)3	–	–	–
Net debt/EBITDAX ratio	1.3	1.8	1.8
Equity ratio (%)	-30	-50	-27
Share of risk capital (%)	13	-10	17
Interest coverage ratio	26	10	8
Operating cash flow/interest ratio	18	9	11
Yield	1	2	4

1 Dividend per share represents the actual paid out dividend per share.

2 Share price at period end in USD is calculated based on quoted share price in SEK and applicable SEK/USD exchange rate as per period end.

3 As the equity at 31 March 2021, 31 December 2020 and 31 March 2020 is negative, these ratios have not been calculated.

Relevant Reconciliations of Alternative Performance Measures

EBITDAX MUSD	1 Jan 2021- 31 Mar 2021 3 months	1 Jan 2020- 31 Mar 2020 3 months	1 Jan 2020- 31 Dec 2020 12 months
Operating profit	764.9	404.2	1,420.7
Add: depletion of oil and gas properties	171.0	147.3	607.7
Add: exploration costs	80.7	27.9	104.9
Add: depreciation of other tangible assets	1.8	1.7	6.9
EBITDAX	1,018.4	581.1	2,140.2

Operating cash flow MUSD	1 Jan 2021- 31 Mar 2021 3 months	1 Jan 2020- 31 Mar 2020 3 months	1 Jan 2020- 31 Dec 2020 12 months
Revenue and other income	1,111.9	695.2	2,564.4
Minus: production costs	-80.9	-51.4	-177.2
Minus: purchase of crude oil from third parties	–	-55.2	-217.8
Minus: current taxes	-507.0	-260.5	-511.8
Operating cash flow	524.0	328.1	1,657.6

Free cash flow MUSD	1 Jan 2021- 31 Mar 2021 3 months	1 Jan 2020- 31 Mar 2020 3 months	1 Jan 2020- 31 Dec 2020 12 months
Cash flows from operating activities (CFFO)	750.2	638.3	1,528.0
Minus: cash flows from investing activities	-224.0	-231.6	-1,079.8
Free cash flow	526.2	406.7	448.2

Adjusted net result MUSD	1 Jan 2021- 31 Mar 2021 3 months	1 Jan 2020- 31 Mar 2020 3 months	1 Jan 2020- 31 Dec 2020 12 months
Net result	68.9	-310.6	384.2
Adjusted for unwinding of loan modification gain	–	9.7	99.7
Adjusted for foreign currency exchange gain or loss	80.7	358.6	-171.0
Adjusted for tax effects of above mentioned items	0.2	8.3	-32.9
Adjusted net result	149.8	66.0	280.0

Net debt MUSD	1 Jan 2021- 31 Mar 2021 3 months	1 Jan 2020- 31 Mar 2020 3 months	1 Jan 2020- 31 Dec 2020 12 months
Bank loans	3,624.0	3,784.0	3,994.0
Minus: cash and cash equivalents	-160.0	-89.8	-82.5
Net debt	3,464.0	3,694.2	3,911.5

Key Ratio Definitions

Adjusted earnings per share: Adjusted net result attributable to shareholders of the Parent Company divided by the weighted average number of shares for the period.

Adjusted earnings per share fully diluted: Adjusted net result attributable to shareholders of the Parent Company divided by the weighted average number of shares for the period after considering any dilution effect.

Adjusted net result: Net result adjusted for the following items:

• Gain or loss from sale of assets is adjusted since the gain or loss does not give an indication of future or periodic performance.
• Impairment and reversal of impairment is adjusted since this affects the economics of an asset for the lifetime of that asset, not only the period in which it is impaired or the impairment is reversed.
• Other items of income and expenses are adjusted when the impact on net result in the period is not reflective of the company's underlying performance in the period. Such items may be unusual or infrequent transactions but they may also include transactions that are significant which would not necessarily qualify as either unusual or infrequent.
• Foreign currency exchange gain or loss is adjusted since the gain or loss does not give an indication of future or periodic performance as currency exchange rates change between periods.
• Tax effects of the above mentioned adjustments to net result

CFFO per share: Cash flow from operating activities (CFFO) divided by the weighted average number of shares for the period.

Dividend per share: paid out dividends per share for the period.

Earnings per share: Net result attributable to shareholders of the Parent Company divided by the weighted average number of shares for the period.

Earnings per share fully diluted: Net result attributable to shareholders of the Parent Company divided by the weighted average number of shares for the period after considering any dilution effect.

EBITDAX (Earnings Before Interest, Taxes, Depletion, Amortisation and Exploration expenses): Operating profit before depletion of oil and gas properties, exploration costs, impairment costs, depreciation of other tangible assets and gain on sale of assets.

EBITDAX per share: EBITDAX divided by the weighted average number of shares for the period.

Equity ratio: Total equity divided by the balance sheet total.

Free cash flow: Cash flow from operating activities less cash flow from investing activities in accordance with the consolidated statement of cash flow.

Free cash flow per share: Free cash flow divided by the weighted average number of shares for the period.

Interest coverage ratio: Result after financial items plus interest expenses plus/less currency exchange differences on financial loans divided by interest expenses.

Net debt: Bank loan less cash and cash equivalents.

Net debt/EBITDAX ratio: Bank loan less cash and cash equivalents divided by EBITDAX of the last four quarters.

Net debt/equity ratio: Bank loan less cash and cash equivalents divided by shareholders' equity.

Operating cash flow: Revenue and other income less production costs less purchase of crude oil from third parties less current taxes and less gain on sale of assets.

Operating cash flow per share: Operating cash flow divided by the weighted average number of shares for the period.

Operating cash flow/interest ratio: Operating cash flow divided by the interest expense for the period.

Return on capital employed: Income before tax plus interest expenses plus/less currency exchange differences on financial loans divided by the average capital employed (the average balance sheet total less current liabilities).

Return on equity: Net result divided by average total equity.

Shareholders' equity per share: Shareholders' equity divided by the number of shares in circulation at period end.

Share of risk capital: The sum of the total equity and the deferred tax provision divided by the balance sheet total.

Weighted average number of shares for the period: The number of shares at the beginning of the period with changes in the number of shares weighted for the proportion of the period they are in issue.

Weighted average number of shares for the period fully diluted: The number of shares at the beginning of the period with changes in the number of shares weighted for the proportion of the period they are in issue after considering any dilution effect.

Yield: dividend per share in relation to quoted share price at the end of the period.

Financial Information

The financial information relating to the three month period ended 31 March 2021 has not been subject to review by the auditors of the Company.

Stockholm, 29 April 2021

Nick Walker President and CEO

The Company will publish the following reports:

The six month report (January June 2021) will be published on 28 July 2021.
The nine month report (January September 2021) will be published on 28 October 2021.
The year end report (January December 2021) will be published on 1 February 2022.

For further information, please contact:

Edward Westropp VP Investor Relations Tel: +41 22 595 10 14 [email protected]

Robert Eriksson Head of Media Communications Tel: +46 701 11 26 15 [email protected]

Definitions and abbreviations

An extensive list of definitions can be found on www.lundin-energy.com under the heading "Definitions".

CHF	Swiss franc
EUR	Euro
NOK	Norwegian Krone
SEK	Swedish Krona
USD	US dollar
TSEK	Thousand SEK
TUSD	Thousand USD
MEUR	Million EUR
MSEK	Million SEK
MUSD	Million USD

	Oil related terms and measurements
bo	Barrels of oil
boe	Barrels of oil equivalents
boepd	Barrels of oil equivalents per day
bopd	Barrels of oil per day
Mbbl	Thousand barrels
Mboe	Thousand barrels of oil equivalents
Mboepd	Thousand barrels of oil equivalents per day
Mbopd	Thousand barrels of oil per day
Mcf	Thousand cubic feet
MMboe	Million barrels of oil equivalents
MMbo	Million barrels of oil

This information is information that Lundin Energy AB is required to make public pursuant to the Securities Markets Act. The information was submitted for publication, through the contact persons set out above, at 07.30 CEST on 29 April 2021.

Forward-Looking Statements

Certain statements made and information contained herein constitute "forward-looking information" (within the meaning of applicable securities legislation). Such statements and information (together, "forward-looking statements") relate to future events, including Lundin Energy's future performance, business prospects or opportunities. Forward-looking statements include, but are not limited to, statements with respect to estimates of reserves and/or resources, future production levels, future capital expenditures and their allocation to exploration and development activities, future drilling and other exploration and development activities. Ultimate recovery of reserves or resources are based on forecasts of future results, estimates of amounts not yet determinable and assumptions of management.

All statements other than statements of historical fact may be forward-looking statements. Statements concerning proven and probable reserves and resource estimates may also be deemed to constitute forward-looking statements and reflect conclusions that are based on certain assumptions that the reserves and resources can be economically exploited. Any statements that express or involve discussions with respect to predictions, expectations, beliefs, plans, projections, objectives, assumptions or future events or performance (often, but not always, using words or phrases such as "seek", "anticipate", "plan", "continue", "estimate", "expect", "may", "will", "project", "predict", "potential", "targeting", "intend", "could", "might", "should", "believe" and similar expressions) are not statements of historical fact and may be "forward-looking statements". Forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. No assurance can be given that these expectations and assumptions will prove to be correct and such forward-looking statements should not be relied upon. These statements speak only as on the date of the information and Lundin Energy does not intend, and does not assume any obligation, to update these forward-looking statements, except as required by applicable laws. These forward-looking statements involve risks and uncertainties relating to, among other things, operational risks (including exploration and development risks), productions costs, availability of drilling equipment, reliance on key personnel, reserve estimates, health, safety and environmental issues, legal risks and regulatory changes, competition, geopolitical risk, and financial risks. These risks and uncertainties are described in more detail under the heading "Risks and Risk Management" and elsewhere in Lundin Energy's annual report. Readers are cautioned that the foregoing list of risk factors should not be construed as exhaustive. Actual results may differ materially from those expressed or implied by such forward-looking statements. Forward-looking statements are expressly qualified by this cautionary statement.

Corporate Head Office Lundin Energy AB (publ) Hovslagargatan 5 SE-111 48 Stockholm, Sweden T +46-8-440 54 50 W lundin-energy.com

AI Terminal

Orrön Energy

2942_10-q_2021-04-29_db108bbe-4024-4980-a57d-c65fc78b97dc.pdf

Report for the THREE MONTHS ended 31 March 2021

Highlights

Financial summary

Comment from Nick Walker, President and CEO of Lundin Energy:

OPERATIONAL REVIEW

Ongoing COVID-19 Crisis

Production

Development

Johan Sverdrup Phase 2

Greater Edvard Grieg Area Tie-Back Projects

Exploration and Appraisal

2021 exploration and appraisal well programme

Decarbonisation

Certified Carbon Neutrally Produced Crude Oil Sale

Decommissioning

Licence Awards and Transactions

Health, Safety and Environment

FINANCIAL REVIEW

Result

Changes in the Group

Revenue and other income

Production costs

Depletion and decommissioning costs

Exploration costs

Purchase of crude oil from third parties

General, administrative and depreciation expenses

Finance income

Finance costs

Share in result of joint ventures

Tax

Balance Sheet

Non-current assets

Current assets

Non-current liabilities

Current liabilities

Changes in working capital

Parent Company

Related Party Transactions

Liquidity

Contingent liabilities

Subsequent Events

Share Data

Remuneration

Unit Bonus Plan

Performance Based Incentive Plan

Accounting Policies

Risks and Risk Management

Ongoing COVID-19 Crisis

Derivative financial instruments

Exchange Rates

Consolidated Income Statement

Consolidated Statement of Comprehensive Income

Consolidated Balance Sheet

Consolidated Statement of Cash Flows

Consolidated Statement of Changes in Equity

Note 14 – Financial Instruments

Note 15 – Additional disclosures

Parent Company Income Statement

Parent Company Comprehensive Income Statement

Parent Company Balance Sheet

Parent Company Cash Flow Statement

Parent Company Statement of Changes in Equity

Key Financial Data

Relevant Reconciliations of Alternative Performance Measures

Key Ratio Definitions

Financial Information

The Company will publish the following reports:

Definitions and abbreviations

Forward-Looking Statements

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