Q YEAR END REPORT 4 2020

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

Highlights

Strong financial performance with free cash flow generation of MUSD 448, operating cost below guidance at USD 2.69 per boe and reduced net debt to USD 3.9 billion
Balance sheet re-financed with USD 5 billion corporate facility with significantly improved terms
Board of Directors propose to increase 2020 dividend by 80 percent to USD 1.80 per share corresponding to MUSD 512
Record quarterly production in the fourth quarter of 185 Mboepd and 2021 production guidance set between 170 to 190 Mboepd
Johan Sverdrup Phase 1 plateau production raised to 500 Mbopd gross, with expectation to increase up to 535 Mbopd by mid-2021
Edvard Grieg reserves increased by 50 MMboe to 350 MMboe gross 2P ultimate recovery, extending plateau a further year to late 2023
Delivering growth with resource additions of 210 percent of production in 2020 and pipeline of new projects with net resources of approximately 200 MMboe being matured for development within the temporary tax incentives
Acceleration of Decarbonisation Strategy achieving carbon neutrality from 2025 from operational emissions

Financial summary

	1 Jan 2020-	1 Oct 2020-	1 Jan 2019-	1 Oct 2019-

















Per share in USD	0.99	0.31	0.80	0.28

Net debt in MUSD	3,911.5	3,911.5	4,006.7	4,006.7

1 Excludes the reported after tax accounting gain of MUSD 756.7 in 2019 on the divestment of a 2.6 percent working interest in the Johan Sverdrup project.

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

"I'm pleased to report that in 2020 Lundin Energy delivered another strong set of results. Our operations and key projects remain on track, despite the impact of COVID-19 and unprecedented oil price volatility, demonstrating the resilience of our industry leading, lowcost business.

"This was a challenging year for all, with the impact from COVID-19 on people's health, society and of course the global oil market. At Lundin Energy we continue to handle the impact with agility and flexibility, safeguarding our people's well-being whilst keeping our main business priorities on course. We exited 2020 with record production in the fourth quarter of 185 Mboepd, resulting in annual production of 165 Mboepd at the top end of the original guidance range, despite the production cuts imposed by the Norwegian government. Operating costs were just USD 2.69 per boe, below the guidance for the year.

"Our world class assets continue to outperform and production is now set to exceed 200 Mboepd by 2023. Edvard Grieg gross 2P ultimate recovery was raised to 350 MMboe, almost double the original project sanction level. Alongside area tie-back developments this extends the production plateau to end 2023, which I anticipate will go further with upsides and area exploration opportunities. At Johan Sverdrup we reached Phase 1 plateau production ahead of schedule and the facilities capacity has been lifted significantly with an expectation of reaching up to 535 Mbopd gross from mid-2021. This is an increase of 95 Mbopd on design levels, and the full field plateau should increase to 720 Mbopd, when Phase 2 starts up in the fourth quarter of 2022.

"Our growth strategy continues to deliver results with total resource additions in 2020 of 210 percent of produced volumes. With a pipeline of nine potential new projects, prioritised for development within the new tax environment, and our active exploration and appraisal programme in 2021, targeting over 300 MMboe of net unrisked resources, I am confident that we can continue to grow resources.

"Financially we had a strong year, despite record low oil prices, delivering free cash flow of MUSD 448, covering our 2020 dividend more than 1.4 times, enabling us to deleverage the business at an average realised oil price of USD 40.0 per barrel. Liquidity was further strengthened with the successful refinancing of the business through a USD 5 billion committed corporate facility, with significantly improved terms. I am pleased to note that the Board of Directors is recommending a 80 percent increased dividend of USD 1.80 per share (in total MUSD 512), clearly demonstrating our commitment to sustain and increase shareholder returns. The Company's policy remains to pay a sustainable dividend even below USD 50 per barrel.

Highlights

"We have also delivered on our Decarbonisation Strategy in 2020. Work continues on the electrification of our key producing assets alongside our investments in renewable energy to offset and replace the electricity we consume. When combined with our natural carbon capture projects, we can now achieve carbon neutrality from 2025; a first for the upstream industry, and showing we can deliver both profitable growth and environmental benefits.

"It is an honour to be taking up the reins of this industry-leading Company and I would like to express my deep gratitude to Alex Schneiter for providing exceptional leadership over the past five years. His foresight and ambition means that Lundin Energy is, and will continue to be, at the forefront of the industry. I would like to thank all our stakeholders for their support during this very challenging year. I look forward to reporting on our active 2021 programme and I am encouraged by the outlook for the business, which is well positioned to deliver resilient, sustainable growth into the future."

Lundin Energy has grown from an oil and gas exploration company into an experienced Nordic energy developer and operator. We continue to explore new ideas, new concepts and new solutions to maintain our position as an industry leader in production efficiency, sustainability and decarbonisation. (Nasdaq Stockholm: LUNE). For more information, please visit us at www.lundin-energy.com or download our App www.myirapp.com/lundin For definitions and abbreviations, see pages 32 and 34.

OPERATIONAL REVIEW

All the reported numbers and updates in the operational review relate to the financial year ended 31 December 2020, unless otherwise specified.

COVID-19 Crisis and Low Oil Price Response

The COVID-19 crisis, its economic impact and the oil price collapse led to a challenging market backdrop during 2020. The main focus of the Company's response has been, and continues to be, on reducing the risk of the virus spreading in the operations and safeguarding the well-being of the Company's employees and contractors, whilst at the same time minimising the potential impact on the business. To date there have been no disruptions to production due to the COVID-19 situation. Detailed contingency plans have been established to mitigate the risk, a key element of which is that all personnel visiting the Company's operated production and drilling sites are now tested for the virus before travelling offshore.

Lundin Energy has high quality, low cost assets, which are resilient in a low oil price environment. Nevertheless, the Company took steps to defer activity and reduce spend, where it did not impact safety, asset integrity or production, in order to further strengthen the financial resilience of the business. Total expenditure reductions and deferrals in 2020 were over MUSD 360 from original guidance, including capital expenditures, operating costs and G&A.

Reserves and Resources

Lundin Energy has 671 million barrels of oil equivalent (MMboe) of proved plus probable net reserves (2P) and 826 MMboe of proved plus probable plus possible net reserves (3P) as at 31 December 2020, as certified by an independent third party. Lundin Energy has additional oil and gas resources which classify as contingent resources (2C) and the best estimate net contingent resources amounted to 275 MMboe as at 31 December 2020. The total resource, which is 2P reserves plus 2C resources, are 946 MMboe as at 31 December 2020.

Production

Production was 164.5 Mboepd, which was above the upper end of the updated guidance range for the year of between 161 and 163 Mboepd, and at the top end of the original guidance range of between 145 and 165 Mboepd. Fourth quarter production was 185.1 Mboepd due to increased facilities capacity and high uptime performance at Edvard Grieg and Johan Sverdrup.

In May 2020, the Norwegian Government announced oil production restriction measures as a response to the oil price collapse and oversupply in the global market. However, in the fourth quarter 2020, the authorities increased the production permits for certain fields, which benefitted the Johan Sverdrup, Edvard Grieg and Alvheim fields.

Operating cost, including netting off tariff income, was USD 2.69 per boe, which is below the updated guidance of USD 2.80 per boe.

Production in Mboepd		1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months	1 Jan 2019- 31 Dec 2019 12 months	1 Oct 2019- 31 Dec 2019 3 months
Crude oil		152.7	171.9	83.5	123.4
Gas		11.8	13.2	9.8	11.7
Total production		164.5	185.1	93.3	135.1
Production in Mboepd	WI1	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months	1 Jan 2019- 31 Dec 2019 12 months	1 Oct 2019- 31 Dec 2019 3 months
Johan Sverdrup	20%	87.6	100.3	14.0	55.5
Edvard Grieg	65%	63.6	72.1	63.7	63.7
Ivar Aasen	1.385%	0.8	0.7	0.8	0.8
Alvheim Area	15% - 35%	12.5	12.0	14.8	15.0
		164.5	185.1	93.3	135.1

1 Lundin Energy's working interest (WI)

Production from Johan Sverdrup Phase 1 was two percent ahead of forecast, driven by a high production efficiency in the fourth quarter of 99 percent and increased facilities capacity. Four production wells and one water injection well were completed during 2020, with results from all five wells in line with or above expectations. The field is currently producing from 12 wells and reservoir performance continues to be excellent, with total well capacity exceeding the available facilities capacity. In the first quarter of 2020, it was announced that due to higher established processing capacity, the Phase 1 plateau production rate was increased from 440 thousand barrels of oil per day (Mbopd) gross to 470 Mbopd. The increased Phase 1 plateau level of 470 Mbopd was achieved in April 2020, more than two months earlier than scheduled. In November 2020, it was announced that following successful capacity testing, the Phase 1 plateau production rate was increased further to 500 Mbopd and as a result the full field plateau, when Phase 2 comes on stream, was increased to 720 Mbopd. The Phase 1 processing capacity is expected to increase further, up to 535 Mbopd, following modification work to upgrade the water injection facilities, which is expected to be complete by mid-2021. Operating costs were USD 1.56 per boe.

Production from the Edvard Grieg field was two percent ahead of forecast, supported by high production efficiency in the fourth quarter of 100 percent and increased available facilities capacity, as a result of Ivar Aasen not utilizing its full contractual share. In September 2020, the Company announced a 50 MMboe increase in Edvard Grieg field gross 2P reserves, lifting the gross 2P ultimate recovery to 350 MMboe. The plateau production period for the Greater Edvard Grieg Area, which also includes the Solveig Phase 1 and Rolvsnes Extended Well Test (EWT) developments, was extended by a further year to late 2023. The increase in reserves and plateau extension are as a result of higher oil in place, following an updated reservoir model which incorporated data referencing the lower water production levels and a 4D seismic survey, showing the injection water flood front to be further away from the production wells than previously predicted. In the third quarter 2020, a planned ten-day maintenance shutdown took place, to take advantage of the flexibility offered by the excess production capacity while production was restricted. The planned three well infill drilling programme at Edvard Grieg commenced post period end in January 2021, using the Rowan Viking jack-up rig. The Edvard Grieg electrification project, which involves the retirement of the existing gas turbine power generation system on the platform, installation of electric boilers to provide process heat and installation of a power cable from Johan Sverdrup to Edvard Grieg, is underway and is expected to be operational in late 2022. Operating costs, including netting off tariff income, were USD 3.47 per boe.

Production from the Ivar Aasen field was four percent below forecast. Two infill wells have been drilled and are expected to come on stream in the first quarter 2021.

Production from the Alvheim Area, consisting of the Alvheim, Volund and Bøyla fields, was in line with forecast reflecting the production restriction measures imposed by the Norwegian Government. One infill well has been drilled in the Alvheim field, which came on stream in November 2020, with results in line with expectations. In December 2020, drilling commenced on a second infill well at the Alvheim field, which is expected to come on stream in the second quarter 2021. In the third quarter 2020, a planned maintenance shutdown took place to take advantage of excess production capacity, due to the aforementioned production restrictions. Operating costs for the Alvheim Area were USD 5.68 per boe.

Development

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	80%	Lundin Energy	-	Q3 2021	3 Mboepd
1 Johan Sverdrup full field

The development expenditure in 2020 was MUSD 640 which was slightly below the updated guidance of MUSD 650.

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 drilling contract for the subsea wells, has been awarded to the Deepsea Atlantic semi-submersible rig, which was the same rig used for the Phase 1 pre-drilled wells. The Johan Sverdrup 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 full field plateau, when Phase 2 comes on stream will be at the increased level of 720 Mbopd. Full field breakeven oil price, including past investments, is estimated at below USD 20 per boe. The PDO for Phase 2 was approved in May 2019.

The Phase 2 capital expenditure is estimated at gross NOK 41 billion (nominal), which is unchanged from the Phase 2 PDO estimate. Construction is ongoing on the second processing platform topsides and jacket, the new modules to be installed on the existing Riser Platform and the subsea facilities. There have been some disruptions to project activities due to COVID-19, which have been effectively managed and first oil remains on schedule for the fourth quarter of 2022, with progress now over 50 percent complete.

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 0.2 kg per boe in 2020 (below the original forecast of approximately 0.7 kg per boe). The project also includes expansion of the power from shore facilities for Phase 2, which includes additional capacity for the Utsira High Power grid, including for the Edvard Grieg field.

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 to the end of 2023. Phase 1 gross 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 estimate for the development is within the PDO estimate of MUSD 810 gross, with an improved breakeven oil price of below 20 USD per boe, based on the recently announced tax incentives. The potential for further phases of development, which will capture the upside potential in the discovered resources, will be de-risked by production performance from Phase 1.

The Rolvsnes EWT project, which was approved by the authorities in July 2019, will be conducted 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 implemented together with the Solveig project to take advantage of contracting and implementation synergies.

In order to manage the COVID-19 risk, a decision was taken to defer activity and both projects are on schedule for revised first oil in the third quarter 2021. The Edvard Grieg field has excess well capacity and the deferrals have no impact on the Company's net production. Installation of the subsea facilities commenced in March 2020 and all production and injection pipelines and the satellite well head structures have been installed. The start of development drilling operations using the West Bollsta semi-submersible rig, is scheduled for the second quarter of 2021. The Solveig Phase 1 project progress is over 50 percent complete and the Rolvsnes EWT project is over 75 percent complete.

Appraisal

2020 appraisal well programme

Licence	Operator	WI	Well	Spud Date	Status
PL894	Wintershall DEA	10%	Balderbrå	January 2020	Completed February 2020

In February 2020, an appraisal well was completed on the Balderbrå gas discovery in PL894 in the Norwegian Sea. The results were below expectations, leading to a reduction in the resource estimate and a commercial development of the discovery is not considered viable.

In June 2020, the Norwegian Government, to stimulate activity, announced temporary tax incentives that apply to PDO's submitted for approval before the end of 2022 and being approved before the end of 2023. These tax incentives significantly improve project economics and the Company has nine potential projects that could be accelerated to benefit from this opportunity. The Company's net resources for these potential projects, inclusive of the acquisition announced in September 2020 of an interest in the Wisting field, totals approximately 200 MMboe, with the main projects being Solveig Phase 2 and Segment D, Lille Prinsen, Rolvsnes Full Field, Iving, Alta, Wisting and the Alvheim Area projects of Kobra East/Gekko and Frosk. The plan is to accelerate appraisal activities and field development studies for all of these potential projects, with the aim of maturing them to PDO within the time-line of the tax incentives.

Exploration

2020 exploration well programme

Licence	Operator	WI	Well	Spud Date	Result
PL917	ConocoPhillips	20%	Hasselbaink	January 2020	Dry
PL820S1	MOL	40%	Evra/Iving	November 2019	Two oil & gas discoveries
PL609/PL1027	Lundin Energy	47.5%	Polmak	October 2020	Dry
PL960	Equinor	20%	Spissa	November 2020	Dry
PL533	Lundin Energy	40%	Bask	December 2020	Dry

1 Lundin Energy's working interest in License PL820S will increase to 41% on closing of the Wintershall DEA transaction

The re-phased and scaled back 2020 exploration drilling programme involved five wells, with the drilling of the Merckx exploration well delayed to 2021. The exploration and appraisal expenditure in 2020 was MUSD 153, slightly below the updated guidance of MUSD 160.

In March 2020, the dual target Evra and Iving prospect in PL820S, located in the Norwegian North Sea close to the Balder and Ringhorne fields, was drilled yielding two discoveries. At Iving, an oil and gas discovery was made with gross resources estimated to be between 12 to 71 MMboe. The well was production tested in the Skagerrak formation and flowed at a maximum rate of around 3,000 barrels per day of light 40 degree API oil, constrained by surface equipment. At Evra, the well encountered gas and oil in Eocene/Paleocene age injectite reservoir sands, with further appraisal required to determine the resource potential. Appraisal drilling is planned in 2021 with the aim of developing the discovery as a tie-back to existing nearby infrastructure. Follow-up prospectivity exists in the licence and will be evaluated in light of this discovery.

Decarbonisation Strategy and Renewable Energy Projects

Since launching the Decarbonisation Strategy in January 2020, good progress has been made across the business with the net carbon intensity for all assets of 2.6 kg CO2 per boe, which is approximately 50 percent lower than the 2019 average, and lower than the Company's target of 4 kg CO2 per boe. This reduction is largely due to Johan Sverdrup coming on stream, which had a carbon intensity during the reporting period of less than 0.2 kg CO2 per boe, and a strong focus within the business of minimising emissions. Lundin Energy's carbon emissions performance is set to improve further with the Edvard Grieg platform being fully electrified in late 2022, when the average net carbon intensity for all the Company's producing assets is expected to be below 2 kg CO2 per boe, approximately one-tenth of the industry average.

A key driver of the Decarbonisation Strategy is the electrification of the Company's main producing assets and the investment in renewable energy projects to replace the Company's net electricity consumption. With electrification of the Utsira High Area, including the Edvard Grieg and Johan Sverdrup fields by late 2022, over 95 percent of the Company's production will be powered from shore, consuming around 500 GWh per annum. To partially replace this electricity usage, two investments have been made in the Leikanger hydropower project in Norway and the Metsälamminkangas (MLK) wind farm project in Finland. When fully operational these projects will together generate around 300 GWh per annum net, which is approximately 60 percent of the Company's net electricity usage from 2023. It is Lundin Energy's strategy to fully replace all net electricity usage for power from shore by 2023 with further direct investments in renewable energy electricity generation.

In 2019, Lundin Energy signed an agreement with Sognekraft AS to acquire a 50 percent non-operated interest in the Leikanger river run off hydropower project, with the transaction closing in June 2020. Leikanger will produce around 208 GWh per annum gross and initial power generation commenced on schedule in June 2020, with performance ahead of expectations, and the project will become fully operational in mid-2021. Net electricity generation from Leikanger during the reporting period was approximately one third of the Company's net electricity usage at Johan Sverdrup over the same period.

In January 2020, Lundin Energy completed a transaction with OX2 AB (OX2) to acquire a 100 percent interest in the MLK onshore wind farm project, which will produce around 400 GWh per annum gross once it is operational in early 2022. The MLK operations will be managed by OX2. In March 2020, Lundin Energy completed a farm-down of 50 percent of the MLK project to Sval Energi AS, a portfolio company of HitecVision, on equivalent terms that the Company acquired the project from OX2. Construction of the wind farm started in April 2020 and is progressing according to plan.

Lundin Energy's total investment commitments in renewable energy projects amounts to approximately MUSD 160 over the period 2020/2021. The renewable expenditure in 2020 was MUSD 96 which was in line with the updated guidance of MUSD 95.

In January 2021, Lundin Energy announced the acceleration of its Decarbonisation Strategy to achieve carbon neutrality for operational emissions from 2025, from the original target of 2030. This change is underpinned by the good progress on the electrification and renewables projects, coupled with a partnership with Land Life Company B.V., to invest MUSD 35 to plant approximately eight million trees between 2021 and 2025, capturing approximately 2.6 million tonnes of CO2.

Decommissioning

The decommissioning plan for the Brynhild field was approved by the UK authorities in June 2020 and by the Norwegian authorities in September 2020. In October 2020, the Rowan Viking jack-up rig completed operations to abandon the four Brynhild sub-sea wells. The contract for the removal of the subsea facilities has been awarded to DeepOcean, with operations planned in the third quarter of 2021.

The Gaupe field ceased production in 2018 and preparation of the decommissioning plan for the field is ongoing.

The decommissioning expenditure in 2020 was MUSD 53 which was in line with the updated guidance of MUSD 50. Following completion of Brynhild and Gaupe decommissioning, the Company has no further planned decommissioning spend until around 2035.

Licence Awards and Transactions

In January 2020, the Company was awarded 12 licences in the 2019 APA licensing round, of which seven are as operator.

In March 2020, Lundin Energy entered into a sales and purchase agreement with Capricorn Norge AS involving the acquisition of a 30 percent working interest in PL1057. The transaction increased Lundin Energy's working interest to 60 percent in PL1057 and the Company has become the operator of the licence.

In September 2020, Lundin Energy entered into a sales and purchase agreement with Vår Energi AS, involving the acquisition of a 50 percent working interest in PL229E.

In October 2020, Lundin Energy entered into a sales and purchase agreement with Idemitsu Petroleum Norge AS involving the acquisition of a 10 percent working interest in the Wisting oil discovery in licences PL537 and PL537B. Wisting is estimated to contain gross resources of 500 MMbo and is scheduled to be one of the next Barents Sea production hubs. Equinor, the operator of Wisting in the development phase, is targeting a PDO by end 2022, to benefit from the temporary tax incentives established by the Norwegian Government in June 2020. The transaction also involves a 15 percent working interest in PL609, PL609B, PL609C, PL609D and PL851, which increases Lundin Energy's working interest from 40 to 55 percent in the Alta discovery. The transaction, which is effective from January 2020, adds estimated net contingent resources of approximately 70 MMboe for a cash consideration of MUSD 125, and was completed in November 2020.

In November 2020, Lundin Energy entered into a sales and purchase agreement with Wintershall Dea Norge AS, involving the acquisition of a 1 percent working interest in PL820S, containing the Iving Discovery with estimated gross resources of 12 to 71 MMboe. The transaction, which was as part of a wider cooperation agreement, is subject to customary Government approvals, and will increase the Company's working interest to 41 percent on completion.

In December 2020, Lundin Energy entered into a sales and purchase agreement with Equinor Energy AS, involving the acquisition of a 20 percent working interest and transfer of the operatorship in PL167, PL167B and PL167C containing the Lille Prinsen discovery. The transaction will increase the Company's working interest to 40 percent in the licenses and is subject to customary Government approvals.

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

Currently the Company holds 101 licences in Norway, which is an increase of approximately 23 percent from the beginning of 2020.

Health, Safety and Environment

In May 2020, one person was seriously injured during an incident on a contractor operated vessel that was working on behalf of the Company on the subsea installation activities for the Edvard Grieg tie-back projects. The incident has been thoroughly investigated and mitigating measures implemented. During the reporting period, one further lost time incident and three medical treatment incidents occurred, resulting in a Lost Time Incident Rate of 1.1 per million hours worked and a Total Recordable Incident Rate of 2.8 per million hours worked. There were no material environmental incidents during the reporting period.

FINANCIAL REVIEW

Result

The operating profit for the year amounted to MUSD 1,420.7 (MUSD 1,970.7), with the decrease compared to the comparative period mainly driven by a MUSD 756.7 after tax accounting gain on the sale of 2.6 percent of Johan Sverdrup during the comparative period. The operating profit for the comparative period excluding this accounting gain amounted to MUSD 1,214.0 with the increase during the year mainly driven by higher sales volumes. Sales volumes increased by 77 percent compared to the comparative period as a result of the startup of production from the Johan Sverdrup field in October 2019, but this was partly offset by lower oil prices and higher depletion charges during the year. Operating profit was also positively impacted by the fact that there were no impairment charges during the year compared to MUSD 128.3 in the comparative period.

The net result for the year amounted to MUSD 384.2 (MUSD 824.9), representing earnings per share of USD 1.35 (USD 2.61). Net result was impacted by a foreign currency exchange gain during the year of MUSD 171.0 (MUSD -131.7), a MUSD 756.7 after tax accounting gain in the comparative period on the sale of 2.6 percent of Johan Sverdrup and a MUSD 128.3 impairment charge in the comparative period. Adjusted net result for the year amounted to MUSD 280.0 (MUSD 252.7), representing adjusted earnings per share of USD 0.99 (USD 0.80). 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 year. Adjusted net result for the fourth quarter amounted to MUSD 86.9 (MUSD 78.9) representing a record high quarterly adjusted net result for the Company.

Earnings before interest, tax, depletion, amortization and exploration expenses (EBITDAX) for the year amounted to MUSD 2,140.2 (MUSD 1,918.4) representing EBITDAX per share of USD 7.53 (USD 6.07), with the increase compared to the comparative period mainly caused by higher sales volumes, partly offset by lower oil prices. EBITDAX for the fourth quarter amounted to MUSD 708.4 (MUSD 695.5) representing a record high quarterly EBITDAX for the Company. Cash flow from operating activities (CFFO) for the year amounted to MUSD 1,528.0 (MUSD 1,378.2), representing CFFO per share of USD 5.38 (USD 4.36) with the increase compared to the comparative period, again impacted by higher sales volumes, partly offset by lower oil prices, further positively impacted by working capital changes during the year but partially offset by higher tax payments during the year. Free cash flow for the year amounted to MUSD 448.2 (MUSD 1,271.7), representing free cash flow per share of USD 1.58 (USD 4.03), with the decrease compared to the comparative period mainly impacted by the cash inflow of MUSD 959.0 from the sale of 2.6 percent of Johan Sverdrup during the comparative period. Free cash flow for the comparative period excluding this cash inflow amounted to MUSD 312.7 with the increase during the year mainly impacted by higher CFFO.

The above mentioned numbers on a per share basis are, compared to the comparative period, positively impacted by the redemption of approximately 54.5 million shares during the third quarter of 2019.

Norwegian tax changes

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 the Special Petroleum Tax (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 the year and an increase in deferred taxes for the year. The changes for the Norwegian SPT will reduce the Company's current tax charge for the years 2020 and 2021 with the cashflow impact spread over the period 2020 to 2022, due to the phasing of the tax installments in Norway.

Changes in the Group

In January 2020, Lundin Energy completed a transaction with OX2 AB (OX2) to acquire a 100 percent interest in the Metsälamminkangas (MLK) wind farm project, in mid Finland. In March 2020, Lundin Energy completed a transaction with Sval Energi AS (Sval), a portfolio company of HitecVision, to farm down 50 percent of its MLK wind farm project. MLK will produce around 400 GWh per annum gross, once it is fully operational in early 2022, from 24 onshore wind turbines. The MLK operations will be managed by OX2. The investment to Lundin Energy, including the acquisition cost, is approximately MUSD 110 over 2020 and 2021 and the project is anticipated to be free cash flow positive from 2022. The 50 percent interest in MLK is recognised as an investment in a joint venture in the consolidated accounts of the Group.

In June 2020, Lundin Energy completed a transaction with Sognekraft AS to acquire a 50 percent non-operated interest in the Leikanger hydropower project, in mid-west Norway. Leikanger will produce around 208 GWh per annum gross, once it is fully operational in 2021, from a river run off hydropower generation scheme. The investment to Lundin Energy, including the acquisition cost, is approximately MUSD 50 and the project is estimated to be free cash flow positive from 2022. The 50 percent interest in Leikanger is recognised as an investment in a joint venture in the consolidated accounts of the Group.

Revenue and other income

Revenue and other income for the year amounted to MUSD 2,564.4 (MUSD 2,948.7) 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 year amounted to MUSD 2,533.2 (MUSD 2,158.6). The average price achieved by Lundin Energy for a barrel of oil equivalent from own production, amounted to USD 38.35 (USD 61.00) and is detailed in the following table. The average Dated Brent price for the year amounted to USD 41.84 (USD 64.21) per barrel and USD 44.16 (USD 63.08) for the fourth quarter.

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

Sales from own production Average price per boe expressed in USD	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months	1 Jan 2019- 31 Dec 2019 12 months	1 Oct 2019- 31 Dec 2019 3 months
Crude oil sales
– Quantity in Mboe	54,263.6	15,441.2	29,769.7	10,730.7
– Average price per bbl	39.96	44.72	65.16	64.93
Gas and NGL sales – Quantity in Mboe – Average price per boe	6,013.2 23.80	1,781.5 32.48	4,235.7 31.77	1,455.8 29.93
Total sales – Quantity in Mboe – Average price per boe	60,276.8 38.35	17,222.7 43.45	34,005.4 61.00	12,186.2 60.75

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

Net sales of crude oil from third party activities for the year amounted to MUSD 221.5 (MUSD 84.3) and consisted 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 year amounted to MUSD 31.2 (MUSD 33.4) and mainly included tariff income of MUSD 23.2 (MUSD 27.2), which is due to net income from Ivar Aasen tariffs paid to Edvard Grieg. Other income for the year also included MUSD 0.8 (MUSD –) relating to Dated Brent differential derivatives.

Gain from sale of assets in the comparative period amounted to MUSD 756.7 and related to the sale of 2.6 percent of Johan Sverdrup.

Production costs

Production costs including under/over lift movements and inventory movements for the year amounted to MUSD 177.2 (MUSD 164.8) and are detailed in Note 2. The total production cost per barrel of oil equivalent produced is detailed in the table below:

Production costs	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months	1 Jan 2019- 31 Dec 2019 12 months	1 Oct 2019- 31 Dec 2019 3 months
Cost of operations
– In MUSD	134.5	32.6	118.1	36.2
– In USD per boe	2.24	1.92	3.47	2.91
Tariff and transportation expenses
– In MUSD	50.7	14.3	46.3	15.6
– In USD per boe	0.84	0.84	1.36	1.25
Operating costs
– In MUSD	185.2	46.9	164.4	51.8
– In USD per boe1	3.08	2.76	4.83	4.16
Change in under/over lift position
– In MUSD	-2.7	1.2	-0.9	-3.5
– In USD per boe	-0.05	0.06	-0.03	-0.28
Change in inventory position
– In MUSD	-11.2	-11.6	-2.8	-3.1
– In USD per boe	-0.19	-0.68	-0.08	-0.25
Other
– In MUSD	5.9	1.5	4.1	1.0
– In USD per boe	0.10	0.09	0.12	0.08
Production costs
– In MUSD	177.2	38.0	164.8	46.2
– In USD per boe	2.94	2.23	4.84	3.71

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 year of USD 3.08 (USD 4.83) per barrel is reduced to USD 2.69 (USD 4.03) when tariff income is netted off. The operating cost for the fourth quarter of USD 2.76 (USD 4.16) per barrel is reduced to USD 2.44 (USD 3.54) when tariff income is netted off.

The total cost of operations for the year amounted to MUSD 134.5 (MUSD 118.1) and the total cost of operations excluding operational projects amounted to MUSD 127.8 (MUSD 108.6). The increase compared to the comparative period related to the start up of production from the Johan Sverdrup field in October 2019, partly offset by a weaker Norwegian Krone.

The cost of operations per barrel for the year amounted to USD 2.24 (USD 3.47) including operational projects and USD 2.12 (USD 3.19) excluding operational projects. The lower unit costs compared to the comparative period are mainly relating to the start up of the Johan Sverdrup field, which has a lower unit operating cost, in addition to a weaker Norwegian Krone.

Tariff and transportation expenses for the year amounted to MUSD 50.7 (MUSD 46.3) or USD 0.84 (USD 1.36) per barrel. The decrease on a per barrel basis compared to the comparative period, is again driven by the start up of production from the Johan Sverdrup field in October 2019, in addition to a weaker 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 -2.7 (MUSD -0.9) in the year 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 -11.2 (MUSD 2.8) in the year due to a cargo lifting at the end of the year 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 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months	1 Jan 2019- 31 Dec 2019 12 months	1 Oct 2019- 31 Dec 2019 3 months
Production volumes	164.5	185.1	93.3	135.1
Inventory movements	-1.7	-6.8	-0.7	-2.7
Production volumes excluding inventory movements	162.8	178.3	92.6	132.4
Sales volumes from own production	164.7	187.2	93.2	132.5
Change in overlift position	-1.9	-8.9	-0.6	-0.1

Other costs for the year amounted to MUSD 5.9 (MUSD 4.1) and related to the business interruption insurance.

Depletion and decommissioning costs

Depletion and decommissioning costs for the year amounted to MUSD 607.7 (MUSD 443.8) at an average rate of USD 10.09 (USD 13.03) per barrel and are detailed in Note 3. The lower depletion costs for the year compared to the comparative period, is due to the start up of production from the Johan Sverdrup field at a lower depletion rate per barrel. The depletion costs are further positively impacted by a lower depletion rate per barrel in USD terms, as the depletion rate per barrel is calculated in Norwegian Krone with the Norwegian Krone having weakened against the USD compared to the comparative period.

Exploration costs

Exploration costs expensed in the income statement for the year amounted to MUSD 104.9 (MUSD 125.6) and are detailed in Note 3. 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.

Impairment costs of oil and gas properties

No impairment costs were charged to the income statement during the period. Impairment costs charged to the income statement in the comparative period amounted to MUSD 128.3 and related to certain licenses in the Barents Sea of which future economic development is considered uncertain. A non-cash pre-tax impairment charge of MUSD 128.3 was recognized with an offsetting MUSD 101.3 deferred tax credit recognized in the income statement, yielding a net after tax charge of MUSD 27.0.

Purchase of crude oil from third parties

Purchase of crude oil from third parties for the year amounted to MUSD 217.8 (MUSD 84.3) and related to crude oil purchased from outside the Group.

General, administrative and depreciation expenses

The general administrative and depreciation expenses for the year amounted to MUSD 36.1 (MUSD 31.2), which included a charge of MUSD 4.8 (MUSD 4.6) in relation to the Group's long-term incentive plans (LTIP), see also Remuneration section on page 14. Fixed asset depreciation expenses for the year amounted to MUSD 6.9 (MUSD 6.7).

Finance income

Finance income for the year amounted to MUSD 172.3 (MUSD 27.5) and is detailed in Note 4.

The net foreign currency exchange gain for the year amounted to MUSD 171.0 (MUSD -131.7). 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 year, the net realised exchange loss on these settled foreign exchange instruments amounted to MUSD 65.6 (MUSD 60.9).

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

Finance costs

Finance costs for the year amounted to MUSD 318.6 (MUSD 322.5) and are detailed in Note 5.

Interest expenses for the year amounted to MUSD 104.3 (MUSD 93.4) and represented the portion of interest charged to the income statement and includes MUSD 9.1 interest expenses in relation to the Idemitsu deal and 2019 taxes paid during the year in Norway. An additional amount of interest of MUSD 25.8 (MUSD 85.7), associated with the funding of the Norwegian development projects was capitalised in the year. The total interest expenses for the year decreased compared to the comparative period as a result of a lower LIBOR rate since the second quarter of 2020 and partly offset by higher average debt relative to the comparative period.

The result on interest rate hedge settlements amounted to a loss of MUSD 44.5 (gain of MUSD 25.7), as a result of the lower LIBOR rate.

The amortisation of the deferred financing fees for the year amounted to MUSD 37.6 (MUSD 19.7) and related mainly to the expensing of the fees incurred in establishing the reserve-based lending facility over the period of usage of the facility. In addition, the unamortised portion of the capitalised financing fees incurred in establishing the reserve-based lending facility, the MUSD 160 revolving credit facility for the renewable power projects and the MUSD 340 unsecured corporate facility were expensed during the year following the successful refinancing in December 2020, see also Liquidity section on page 13.

Loan facility commitment fees for the year amounted to MUSD 11.6 (MUSD 10.9) and include commitment fees in relation to the revolving credit facility for the financing of the renewable power projects and the MUSD 340 unsecured corporate facility.

The unwinding of the loan modification gain for the year amounted to MUSD 99.7 (MUSD 41.5) 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. In addition, the remaining portion of the capitalised loan modification gain was expensed during the year following the successful refinancing in December 2020

Share in result of joint ventures and associated company

Share in result of joint ventures and associated company for the year amounted to MUSD -0.1 (MUSD -1.8) and related to the 50 percent non-operated interest in the Leikanger hydropower project in Norway, with the project commencing production during the second quarter 2020. The loss in the comparative period related to the share in the result of the investment in Mintley Caspian Ltd. and this company is now liquidated.

Tax

The overall tax charge for the year amounted to MUSD 890.1 (MUSD 849.0) and is detailed in Note 6.

The current tax charge for the year amounted to MUSD 511.8 (MUSD 405.8) and mainly related to Norway. The current tax charge for Norway for the year related to both Corporate Tax and Special Petroleum Tax (SPT). The SPT tax losses were fully utilised during the fourth quarter of 2019, which resulted in increased current tax charges for the year and the current tax charge for Norway for the comparative period related therefore, to Corporate Tax only. The paid tax installments in Norway during the year amounted to MUSD 426.0, which has in combination with the current tax charge for the year and exchange rate movements resulted in an increase in current tax liabilities compared to the end of last year from MUSD 343.3 to MUSD 444.4. 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 the year and an increase in deferred tax for the year.

The deferred tax charge for the year amounted to MUSD 378.3 (MUSD 443.2) 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 year 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 year 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 year was mainly impacted by the reported foreign currency exchange gain and the effective tax rate on the adjusted net results for the year amounted to 77 percent.

Balance Sheet

Non-current assets

Oil and gas properties amounted to MUSD 5,902.4 (MUSD 5,473.2) and are detailed in Note 7.

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

Development expenditure in MUSD	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months	1 Jan 2019- 31 Dec 2019 12 months	1 Oct 2019- 31 Dec 2019 3 months
Norway	639.8	148.4	672.3	174.3
Development expenditure	639.8	148.4	672.3	174.3

Development expenditure of MUSD 639.8 (MUSD 672.3) was incurred in Norway during the year, primarily on the Johan Sverdrup and Solveig fields. In addition an amount of MUSD 25.8 (MUSD 85.7) of interest was capitalised.

Exploration and appraisal expenditure in MUSD	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months	1 Jan 2019- 31 Dec 2019 12 months	1 Oct 2019- 31 Dec 2019 3 months
Norway	152.9	67.1	298.4	62.1
Exploration and appraisal expenditure	152.9	67.1	298.4	62.1

Exploration and appraisal expenditure of MUSD 152.9 (MUSD 298.4) was incurred in Norway during the year, primarily for the exploration and appraisal wells as summarized on pages 5 and 6.

Other tangible fixed assets amounted to MUSD 45.2 (MUSD 49.4) and are detailed in Note 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 110.6 (MUSD –) 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, see also page 6.

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

Renewables investments in MUSD	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months	1 Jan 2019- 31 Dec 2019 12 months	1 Oct 2019- 31 Dec 2019 3 months
MLK Windfarm – Finland	46.3	11.1	–	–
Leikanger Hydropower – Norway	49.8	4.9	–	–
Renewables investments	96.1	16.0	–	–

Financial assets amounted to MUSD 13.5 (MUSD 14.3) 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 12.7 (MUSD 12.4).

Trade and other receivables amounted to MUSD 17.3 (MUSD –) and related to prepayments with a long-term nature and are detailed in Note 10.

Derivative instruments amounted to MUSD 3.8 (MUSD 2.7) and related to the marked-to-market gain on outstanding currency hedge contracts due to be settled after twelve months.

Current assets

Inventories amounted to MUSD 59.1 (MUSD 40.7) and included both well supplies and hydrocarbon inventories. Hydrocarbon inventories included a cargo lifting at the end of the year that was sold in early 2021.

Trade and other receivables amounted to MUSD 278.6 (MUSD 349.5) and are detailed in Note 10. Trade receivables, which are all current, amounted to MUSD 215.5 (MUSD 305.1) with the decrease mainly caused by lower oil prices partly offset by higher sales volumes in December 2020. Underlift amounted to MUSD 5.7 (MUSD 2.0) and was attributable to an underlift position on the producing fields, mainly relating to oil from the Johan Sverdrup field. Joint operations debtors relating to various joint venture receivables amounted to MUSD 21.8 (MUSD 11.4). Prepaid expenses and accrued income amounted to MUSD 26.5 (MUSD 23.9) and represented mainly prepaid operational and insurance expenditure. Other current assets amounted to MUSD 9.1 (MUSD 7.1).

Derivative instruments amounted to MUSD 12.1 (MUSD 11.3) 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 82.5 (MUSD 85.3). Cash balances are mainly held to meet ongoing operational funding requirements.

Non-current liabilities

Financial liabilities amounted to MUSD 3,983.9 (MUSD 3,888.4) and are detailed in Note 11. Bank loans amounted to MUSD 3,994.0 (MUSD 4,000.0) and related to the long-term portion of the outstanding bank loans. Capitalised financing fees relating to the establishment of the facilities amounted to MUSD 37.1 (MUSD 37.1) and are being amortised over the expected life of the facilities. The lease commitments amounted to MUSD 27.0 (MUSD 31.1) 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.

Provisions amounted to MUSD 565.6 (MUSD 528.1) and are detailed in Note 12. The provision for site restoration amounted to MUSD 560.5 (MUSD 522.2) 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 16.0 (MUSD 49.2). The increase in site restoration is mainly caused by additional liability following installations for the development projects in combination with the strengthening of the Norwegian Krone during the year partly offset by decommissioning work done on the Brynhild field.

Deferred tax liabilities amounted to MUSD 2,893.9 (MUSD 2,412.7). 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 144.7 (MUSD 110.8) 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 6.1 (MUSD 97.5) and are detailed in Note 11. Current financial liabilities related mainly to the short-term portion of the outstanding lease commitments and included in the comparative period MUSD 92.0 relating to the short-term portion of the outstanding bank loans.

Dividends amounted to MUSD 72.3 (MUSD 106.0) and related to the cash dividend approved by the AGM held on 31 March 2020 in Stockholm, paid in quarterly installments.

Trade and other payables amounted to MUSD 202.5 (MUSD 177.4) and are detailed in Note 13. Overlift amounted to MUSD 1.6 (MUSD 0.9) and was attributable to an overlift position mainly in relation to condensate from the Johan Sverdrup and Edvard Grieg fields. Joint operations creditors and accrued expenses amounted to MUSD 151.3 (MUSD 133.6) and related to activity in Norway. Other accrued expenses amounted to MUSD 31.7 (MUSD 16.6) and other current liabilities amounted to MUSD 9.2 (MUSD 8.5).

Derivative instruments amounted to MUSD 87.6 (MUSD 33.2) 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 444.4 (MUSD 343.3) and related mainly to Norway. The current tax liabilities have decreased from MUSD 479.0 as of the end of the third quarter 2020 to MUSD 444.4 as of the end of the year mainly due to cash taxes payments of MUSD 337.6 during the fourth quarter 2020 and a current tax charge for the fourth quarter of MUSD 260.6.

Current provisions amounted to MUSD 21.3 (MUSD 55.9) and are detailed in Note 12. The short-term portion of the future decommissioning obligations amounted to MUSD 16.0 (MUSD 49.2) mainly relating to the Brynhild field. The short-term portion of the provision for Lundin Energy's Unit Bonus Plan amounted to MUSD 5.3 (MUSD 6.7).

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 year amounted to MSEK 2,641.9 (MSEK 18,885.5). The net result for the year included MSEK 2,867.8 (MSEK 19,148.4) financial income as a result of received dividends from a subsidiary. The net result excluding received dividends amounted to MSEK -225.9 (MSEK -262.9).

The net result for the year included general and administrative expenses of MSEK 240.1 (MSEK 248.1) and net finance expenses of MSEK 5.3 (MSEK 33.7) when excluding the received dividends as mentioned above.

Related Party Transactions

During the year, 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 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 five year corporate credit facility replaced the reserve-based lending facility, the MUSD 160 revolving credit facility for the renewable power projects and the MUSD 340 unsecured corporate facility.

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 1999 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

In January 2021, drilling was completed on the Bask prospect in PL533B in the southern Barents Sea and was dry and will be expensed in the first quarter 2021.

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 year.

The AGM of Lundin Energy held on 31 March 2020 in Stockholm approved a cash dividend distribution for the year 2019 of USD 1.00 per share, to be paid in quarterly installments of USD 0.25 per share. Before payment, each quarterly dividend of USD 0.25 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 2,867.8, equaling MUSD 284.1 based on the exchange rate on the date of AGM approval.

The first dividend payment was made on 7 April 2020, the second dividend payment was made on 8 July 2020, the third dividend payment was made on 7 October 2020 and the fourth dividend payment was made on 8 January 2021.

2020 dividend proposal

Lundin Energy's objective is to create attractive shareholder returns by investing through the business cycle with capital investments allocated to exploration, development and production assets. The Company's expectation is to create shareholder returns both through share price appreciation and by distributing a sustainable yearly dividend - paid in quarterly instalments and denominated in USD with the plan of maintaining or increasing the dividend over time in line with the Company's financial performance and being sustainable below an oil price of USD 50 per barrel. The dividend shall be sustainable in the context of allowing the Company to continue to pursue its organic growth strategy and to develop its contingent resources whilst maintaining a conservative gearing ratio and retaining an appropriate liquidity position within its available credit lines.

In accordance with the dividend policy, the Board of Directors will propose to the 2021 Annual General Meeting a 2020 dividend of USD 1.80 per share, corresponding to USD 512 million (rounded off), to be paid in quarterly instalments of USD 0.45 per share, corresponding to USD 128 million (rounded off). 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. The SEK amount per share to be distributed each quarter will be announced in a press release four business days prior to each record date.

The first dividend payment is expected to be paid around 8 April 2021, with an expected record date of 1 April 2021 and expected exdividend date of 31 March 2021. The second dividend payment is expected to be paid around 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 around 7 October 2021, with an expected record date of 4 October 2021 and an expected ex-dividend date of 1 October 2021. The fourth dividend payment is expected to be paid around 11 January 2022, with an expected record date of 5 January 2022 and an 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 2019 Annual Report and in the materials provided to shareholders in respect of the 2020 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 December 2020 were 69,653, 123,184 and 266,737 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 December 2020 was 393,113 and the awards vest over three years from 1 July 2020 subject to certain performance conditions being met. 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 December 2020 was 302,526 and the awards vest over three years from 1 July 2019 subject to certain performance conditions being met. 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 December 2020 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.

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).

Lundin Energy has reclassified currency translation reserve balances within equity in accordance with IAS8 in relation to the deconsolidation of the Russian operations back in 2017. Reported Shareholder' equity is not affected by this reclassification.

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 2019.

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 2019 Annual Report.

COVID-19 Crisis and Low Oil Price Response

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 December 2020, Lundin Energy had outstanding foreign currency contracts as summarised below:

Buy	Sell	Average contractual Exchange rate	Settlement period
MNOK 4,332.6	MUSD 516.5	NOK 8.39:USD 1	Jan 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 December 2020 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%	Jan 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 year, the following currency exchange rates have been used.

	31 Dec 2020		31 Dec 2019
	Average	Period end	Average	Period end
1 USD equals NOK	9.4146	8.5326	8.8003	8.7803
1 USD equals Euro	0.8762	0.8149	0.8932	0.8902
1 USD equals SEK	9.2092	8.1772	9.4581	9.2993

	Fourth quarter 2020 Average	Fourth quarter 2019 Average
1 USD equals NOK	9.0231	9.1142
1 USD equals Euro	0.8384	0.9032
1 USD equals SEK	8.6105	9.6143

Consolidated Income Statement

Expressed in MUSD	Note	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months	1 Jan 2019- 31 Dec 2019 12 months	1 Oct 2019- 31 Dec 2019 3 months
Revenue and other income	1
Revenue		2,533.2	773.4	2,158.6	740.3
Gain from sale of assets		–	–	756.7	–
Other income		31.2	6.3	33.4	9.4
		2,564.4	779.7	2,948.7	749.7

Cost of sales
Production costs	2	-177.2	-38.0	-164.8	-46.2
Depletion and decommissioning costs		-607.7	-160.9	-443.8	-142.2
Exploration costs		-104.9	-57.6	-125.6	-40.9
Impairment costs of oil and gas properties		–	–	-128.3	-128.3
Purchase of crude oil from third parties		-217.8	-24.5	-84.3	–
Gross profit	3	1,456.8	498.7	2,001.9	392.1

General, administration and depreciation expenses		-36.1	-10.6	-31.2	-9.6
Operating profit		1,420.7	488.1	1,970.7	382.5

Net financial items Finance income		172.3	171.3	27.5	3.7
	4
Finance costs	5	-318.6 -146.3	-60.4 110.9	-322.5 -295.0	44.1 47.8

Share in result of joint ventures and associated company		-0.1	-0.1	-1.8	-0.5

Profit before tax		1,274.3	598.9	1,673.9	429.8
Income tax	6	-890.1	-295.2	-849.0	-274.5
Net result		384.2	303.7	824.9	155.3

Attributable to: Shareholders of the Parent Company		384.2	303.7	824.9	155.3
Non-controlling interest		–	–	–	–
		384.2	303.7	824.9	155.3

Earnings per share – USD		1.35	1.07	2.61	0.56
Earnings per share fully diluted – USD		1.35	1.07	2.61	0.56

Adjusted earnings per share – USD		0.99	0.31	0.80	0.28
Adjusted earnings per share fully diluted – USD		0.98	0.30	0.80	0.28

Consolidated Statement of Comprehensive Income

Expressed in MUSD	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months	1 Jan 2019- 31 Dec 2019 12 months	1 Oct 2019- 31 Dec 2019 3 months
Net result	384.2	303.7	824.9	155.3

Items that may be subsequently reclassified to profit or loss:
Exchange differences foreign operations	-210.1	-63.7	29.0	-45.1
Cash flow hedges	-63.4	115.1	-82.5	89.6
Other comprehensive income, net of tax	-273.5	51.4	-53.5	44.5

Total comprehensive income	110.7	355.1	771.4	199.8

Attributable to:
Shareholders of the Parent Company	110.7	355.1	771.4	199.8
Non-controlling interest	–	–	–	–
	110.7	355.1	771.4	199.8

Consolidated Balance Sheet

Expressed in MUSD	Note	31 December 2020	31 December 2019
ASSETS
Non-current assets
Oil and gas properties	7	5,902.4	5,473.2
Other tangible fixed assets	8	45.2	49.4
Goodwill		128.1	128.1
Investments in joint ventures		110.6	–
Financial assets	9	13.5	14.3
Trade and other receivables	10	17.3	–
Derivative instruments	14	3.8	2.7
Total non-current assets		6,220.9	5,667.7

Current assets
Inventories		59.1	40.7
Trade and other receivables	10	278.6	349.5
Derivative instruments	14	12.1	11.3
Cash and cash equivalents Total current assets		82.5 432.3	85.3 486.8

TOTAL ASSETS		6,653.2	6,154.5
EQUITY AND LIABILITIES
Equity
Shareholders´ equity		-1,769.1	-1,598.8
Liabilities
Non-current liabilities
Financial liabilities	11	3,983.9	3,888.4
Provisions	12	565.6	528.1
Deferred tax liabilities		2,893.9	2,412.7
Derivative instruments	14	144.7	110.8
Total non-current liabilities		7,588.1	6,940.0
Current liabilities
Financial liabilities	11	6.1	97.5
Dividends		72.3	106.0
Trade and other payables	13	202.5	177.4
Derivative instruments	14	87.6	33.2
Current tax liabilities		444.4	343.3
Provisions	12	21.3	55.9
Total current liabilities		834.2	813.3
Total liabilities		8,422.3	7,753.3
TOTAL EQUITY AND LIABILITIES		6,653.2	6,154.5

Consolidated Statement of Cash Flows

Expressed in MUSD	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months	1 Jan 2019- 31 Dec 2019 12 months	1 Oct 2019- 31 Dec 2019 3 months
Cash flows from operating activities
Net result	384.2	303.7	824.9	155.3
Adjustments for:
Gain from sale of assets	–	–	-756.7	–
Exploration costs	104.9	57.6	125.6	40.9
Depletion, depreciation and amortisation	614.6	162.6	450.5	143.9
Impairment of oil and gas properties	–	–	128.3	128.3
Current tax	511.8	260.6	405.8	325.3
Deferred tax	378.3	34.6	443.2	-50.8
Long-term incentive plans	9.5	4.1	14.7	4.6
Foreign currency exchange gain/ loss	-230.3	-260.6	70.8	-120.5
Interest expense	104.3	26.4	93.4	38.7
Unwinding of loan modification gain	99.7	70.6	41.5	10.1
Amortisation of deferred financing fees	37.6	25.3	19.7	3.9
Other	6.3	-6.5	17.8	4.4
Interest received	0.8	0.2	1.8	0.5
Interest paid	-126.6	-33.3	-177.4	-59.2
Income taxes paid / received	-428.5	-337.6	-132.7	-97.3
Changes in working capital	61.4	-31.0	-193.0	-135.2
Total cash flows from operating activities	1,528.0	276.7	1,378.2	392.9
Cash flows from investing activities
Investment in oil and gas properties	-919.7	-340.5	-1,057.8	-235.9
Investment in renewable energy business1	-99.8	-19.0	-1.2	-1.2
Investment in other fixed assets	-2.4	-0.8	-2.5	-1.1
Investment in financial assets	–	–	-0.3	–
Disposal of fixed assets2	–	–	959.0	–
Decommissioning costs paid	-57.9	-13.9	-3.7	-0.9
Total cash flows from investing activities	-1,079.8	-374.2	-106.5	-239.1
Cash flows from financing activities
Net drawdown/repayment of corporate credit facility	3,994.0	3,994.0	–	–
Net drawdown/repayment of reserve-based lending facility	-4,092.0	-3,836.0	627.0	-58.0
Repayment of principal portion of lease commitments	-3.2	-0.8	-3.4	-0.8
Financing fees paid	-36.8	-34.3	-3.3	–
Dividends paid	-318.2	-71.1	-355.6	-105.1
Share redemption	–	–	-1,517.2	–
Total cash flows from financing activities	-456.2	51.8	-1,252.5	-163.9
	-8.0	-45.7	19.2	-10.1
Change in cash and cash equivalents Cash and cash equivalents at the beginning of the period	85.3	129.2	66.8	95.1
Currency exchange difference in cash and cash equivalents	5.2	-1.0	-0.7	0.3
Cash and cash equivalents at the end of the period	82.5	82.5	85.3	85.3

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

2 Cash received on the divestment of a 2.6 percent working interest in the Johan Sverdrup field on closing including interest and pro and contra funding settlement from effective date to completion date as well as working capital balances and incurred expenses

Consolidated Statement of Changes in Equity

		Additional
		paid-in
Expressed in MUSD	Share capital	capital/Other reserves	Retained earnings	Dividends	Total equity
At 1 January 2019	0.5	-178.6	-205.7	–	-383.8
Reclassification currency translation reserves	–	76.1	-76.1	–	–
Restated equity at 1 January 2019	0.5	-102.5	-281.8	–	-383.8
Comprehensive income
Net result	–	–	824.9	–	824.9
Other comprehensive income	–	-53.5	–	–	-53.5
Total comprehensive income	–	-53.5	824.9	–	771.4
Transactions with owners
Distributions	–	–	–	-501.0	-501.0
Share redemption	-0.1	–	-1,476.9	–	-1,477.0
Bonus issue (sw. fondemission)	0.1	–	-0.1	–	–
Share based payments	–	-13.7	–	–	-13.7
Value of employee services	–	–	5.3	–	5.3
Total transaction with owners	–	-13.7	-1,471.7	-501.0	-1,986.4
At 31 December 2019	0.5	-169.7	-928.6	-501.0	-1,598.8
Transfer of prior year dividends	–	–	-501.0	501.0	–
Comprehensive income
Net result	–	–	384.2	–	384.2
Other comprehensive income	–	-273.5	–	–	-273.5
Total comprehensive income	–	-273.5	384.2	–	110.7
Transactions with owners
Distributions	–	–	–	-284.1	-284.1
Issuance of treasury shares	–	7.3	–	–	7.3
Share based payments	–	-9.6	–	–	-9.6
Value of employee services	–	–	5.4	–	5.4
Total transaction with owners	–	-2.3	5.4	-284.1	-281.0
At 31 December 2020	0.5	-445.5	-1,040.0	-284.1	-1,769.1

Note 1 – Revenue and other income MUSD	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months	1 Jan 2019- 31 Dec 2019 12 months	1 Oct 2019- 31 Dec 2019 3 months
Revenue
Crude oil from own production	2,168.5	690.5	1,939.8	696.8
Crude oil from third party activities	221.5	24.9	84.3	–
Condensate	63.8	23.6	41.4	17.8
Gas	79.4	34.4	93.1	25.7
Sales of oil and gas	2,533.2	773.4	2,158.6	740.3

Gain from sale of assets	–	–	756.7	–
Other income	31.2	6.3	33.4	9.4
Revenue and other income	2,564.4	779.7	2,948.7	749.7

Note 2 – Production costs MUSD	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months	1 Jan 2019- 31 Dec 2019 12 months	1 Oct 2019- 31 Dec 2019 3 months
Cost of operations	134.5	32.6	118.1	36.2
Tariff and transportation expenses	50.7	14.3	46.3	15.6
Change in under/over lift position	-2.7	1.2	-0.9	-3.5
Change in inventory position	-11.2	-11.6	-2.8	-3.1
Other	5.9	1.5	4.1	1.0
Production costs	177.2	38.0	164.8	46.2

Note 3 – Segment information MUSD	1 Jan 2020- 31 Dec 2020	1 Oct 2020- 31 Dec 2020	1 Jan 2019- 31 Dec 2019	1 Oct 2019- 31 Dec 2019
Norway	12 months	3 months	12 months	3 months
Crude oil from own production	2,168.5	690.5	1,939.8	696.8
Condensate	63.8	23.6	41.4	17.8
Gas	79.4	34.4	93.1	25.7
Revenue	2,311.7	748.5	2,074.3	740.3
Gain from sale of assets	–	–	756.7	–
Other income	30.3	6.3	33.4	9.4
Revenue and other income	2,342.0	754.8	2,864.4	749.7
Production costs	-177.2	-38.0	-164.8	-46.2
Depletion and decommissioning costs	-607.7	-160.9	-443.8	-142.2
Exploration costs	-104.9	-57.6	-125.6	-40.9
Impairment costs of oil and gas properties	–	–	-128.3	-128.3
Gross profit	1,452.2	498.3	2,001.9	392.1

Other Crude oil from third party activities	221.5	24.9	84.3	–
Revenue	221.5	24.9	84.3	–
Other income	0.9	–	–	–
Revenue and other income	222.4	24.9	84.3	–
Purchase of crude oil from third parties	-217.8	-24.5	-84.3	–
Gross profit	4.6	0.4	0.0	–

	1 Jan 2020-	1 Oct 2020-	1 Jan 2019-	1 Oct 2019-
Note 3 – Segment information cont.	31 Dec 2020	31 Dec 2020	31 Dec 2019	31 Dec 2019
MUSD	12 months	3 months	12 months	3 months
Total
Crude oil from own production	2,168.5	690.5	1,939.8	696.8
Crude oil from third party activities	221.5	24.9	84.3	–
Condensate	63.8	23.6	41.4	17.8
Gas	79.4	34.4	93.1	25.7
Revenue	2,533.2	773.4	2,158.6	740.3
Gain from sale of assets	–	–	756.7	–
Other income	31.2	6.3	33.4	9.4
Revenue and other income	2,564.4	779.7	2,948.7	749.7
Production costs	-177.2	-38.0	-164.8	-46.2
Depletion and decommissioning costs	-607.7	-160.9	-443.8	-142.2
Exploration costs	-104.9	-57.6	-125.6	-40.9
Impairment costs of oil and gas properties	–	–	-128.3	-128.3
Purchase of crude oil from third parties	-217.8	-24.5	-84.3	–
Gross profit	1,456.8	498.7	2,001.9	392.1

Within each segment, revenues from transactions with a single external customer amount to ten percent or more of revenue for that segment.

Note 4 – Finance income MUSD	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months	1 Jan 2019- 31 Dec 2019 12 months	1 Oct 2019- 31 Dec 2019 3 months
Foreign currency exchange gain, net	171.0	171.0	–	–
Interest income	1.3	0.3	1.8	0.5
Gain on interest rate hedge settlement	–	–	25.7	3.2
Finance income	172.3	171.3	27.5	3.7

Note 5 – Finance costs MUSD	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months	1 Jan 2019- 31 Dec 2019 12 months	1 Oct 2019- 31 Dec 2019 3 months
Foreign currency exchange loss, net	–	-85.2	131.7	-106.0
Interest expense	104.4	26.5	93.4	38.7
Loss on interest rate hedge settlement	44.5	15.2	–	4.5
Unwinding of site restoration discount	19.2	5.1	17.9	3.9
Amortisation of deferred financing fees	37.6	25.3	19.7	2.0
Loan facility commitment fees	11.5	2.8	10.9	–
Unwinding of loan modification gain	99.7	70.6	41.5	10.1
Other	1.7	0.1	7.4	2.7
Finance costs	318.6	60.4	322.5	-44.1

Note 6 – Income tax MUSD	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months	1 Jan 2019- 31 Dec 2019 12 months	1 Oct 2019- 31 Dec 2019 3 months
Current tax	511.8	260.6	405.8	325.3
Deferred tax	378.3	34.6	443.2	-50.8
Income tax	890.1	295.2	849.0	274.5

Note 7 – Oil and gas properties MUSD	31 December 2020	31 December 2019
Norway
Producing assets	3,776.9	4,065.3
Assets under development	1,216.1	652.2
Capitalised exploration and appraisal expenditure	909.4	755.7
	5,902.4	5,473.2

Note 8 – Other tangible fixed assets MUSD	31 December 2020	31 December 2019
Right of use assets	31.8	35.9
Other	13.4	13.5
	45.2	49.4

Note 9 – Financial assets MUSD	31 December 2020	31 December 2019
Contingent consideration	12.7	12.4
Associated companies	0.3	0.3
Other	0.5	1.6
	13.5	14.3

Note 10 – Trade and other receivables
MUSD	31 December 2020	31 December 2019
Non-current:
Prepaid expenses and accrued income	17.3	–
	17.3	–
Current:
Trade receivables	215.5	305.1
Underlift	5.7	2.0
Joint operations debtors	21.8	11.4
Prepaid expenses and accrued income	26.5	23.9
Other	9.1	7.1
	278.6	349.5

	295.9	349.5

Note 11 – Financial liabilities

MUSD	31 December 2020	31 December 2019
Non-current:
Bank loans	3,994.0	4,000.0
Capitalised financing fees	-37.1	-37.1
Capitalised loan modification gain	–	-105.6
Lease commitments	27.0	31.1
	3,983.9	3,888.4
Current:
Bank loans	–	92.0
Lease commitments	5.7	5.5
Others	0.4	–
	6.1	97.5

	3,990.0	3,985.9

Note 12 – Provisions MUSD	31 December 2020	31 December 2019
Non-current:
Site restoration	560.5	522.2
Long-term incentive plans	2.3	2.7
Other	2.8	3.2
	565.6	528.1
Current:
Site restoration	16.0	49.2
Long-term incentive plans	5.3	6.7
	21.3	55.9

	586.9	584.0

Note 13 – Trade and other payables

MUSD	31 December 2020	31 December 2019
Trade payables	8.7	17.8
Overlift	1.6	0.9
Joint operations creditors and accrued expenses	151.3	133.6
Other accrued expenses	31.7	16.6
Other	9.2	8.5
	202.5	177.4

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 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	–
31 December 2019
MUSD	Level 1	Level 2	Level 3
Assets
Contingent consideration	–	–	12.4
Derivative instruments – non-current	–	2.7	–
Derivative instruments – current	–	11.3	–
	–	14.0	12.4
Liabilities
Derivative instruments – non-current	–	110.8	–
Derivative instruments – current	–	33.2	–
	–	144.0	–

There were no transfers between the levels during the year.

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 2020.

Note 15 – Additional disclosures

Additional disclosures supplementing the financial statements are included in the Financial Review section of this report on pages 8-15.

Parent Company Income Statement

	1 Jan 2020-	1 Oct 2020-	1 Jan 2019-	1 Oct 2019-
Expressed in MSEK	31 Dec 2020	31 Dec 2020	31 Dec 2019	31 Dec 2019
	12 months	3 months	12 months	3 months
Revenue	19.5	7.2	18.9	9.4

General and administration expenses	-240.1	-64.4	-248.1	-77.6
Operating loss	-220.6	-57.2	-229.2	-68.2


Net financial items
Finance income	2,867.8	–	19,148.5	-11.3
Finance costs	-5.3	-1.2	-33.8	-0.6
	2,862.5	-1.2	19,114.7	-11.9

Profit before tax	2,641.9	-58.4	18,885.5	-80.1

Income tax	–	–	–	–

Net result	2,641.9	-58.4	18,885.5	-80.1

Parent Company Comprehensive Income Statement

Expressed in MSEK	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months	1 Jan 2019- 31 Dec 2019 12 months	1 Oct 2019- 31 Dec 2019 3 months
Net result	2,641.9	-58.4	18,885.5	-80.1
Other comprehensive income	–	–	–	–
Total comprehensive income	2,641.9	-58.4	18,885.5	-80.1
Attributable to:
Shareholders of the Parent Company	2,641.9	-58.4	18,885.5	-80.1
	2,641.9	-58.4	18,885.5	-80.1

Parent Company Balance Sheet

Expressed in MSEK	31 December 2020	31 December 2019
ASSETS
Non-current assets
Shares in subsidiaries	55,118.9	55,118.9
Other tangible fixed assets	0.5	0.4
Total non-current assets	55,119.4	55,119.3

Current assets
Receivables	568.5	1,107.4
Cash and cash equivalents	26.6	31.7
Total current assets	595.1	1,139.1

TOTAL ASSETS	55,714.5	56,258.4

SHAREHOLDERS´EQUITY AND LIABILITIES
Shareholders´ equity including net result for the period	55,080.0	55,242.8

Non-current liabilities
Provisions	0.9	1.0
Total non-current liabilities	0.9	1.0

Current liabilities
Dividends	591.5	985.7
Other liabilities	42.1	28.9
Total current liabilities	633.6	1,014.6

Total liabilities	634.5	1,015.6

TOTAL EQUITY AND LIABILITIES	55,714.5	56,258.4

Parent Company Cash Flow Statement

Expressed in MSEK	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months	1 Jan 2019- 31 Dec 2019 12 months	1 Oct 2019- 31 Dec 2019 3 months
Cash flow from operations
Net result	2,641.9	-58.4	18,885.5	-80.1
Adjustment for non-cash related items	-711.0	718.6	-1,157.9	1,171.5
Changes in working capital	1,007.3	-15.5	133.0	-68.3
Total cash flow from operations	2,938.2	644.7	17,860.6	1,023.1
Cash flow from investing
Investments in other fixed assets	-0.2	–	-0.1	–
Total cash flow from investing	-0.2	–	-0.1	–
Cash flow from financing
Dividends paid	-3,003.1	-648.3	-3,347.6	-1,025.4
Issuance of treasury shares	63.1	–	–	–
Share redemption	–	–	-14,510.3	–
Total cash flow from financing	-2,940.0	-648.3	-17,857.9	-1,025.4
Change in cash and cash equivalents	-2.0	-3.6	2.6	-2.3
Cash and cash equivalents at the beginning of the period	31.7	32.1	29.5	36.9
Currency exchange difference in cash and cash equivalents	-3.1	-1.9	-0.4	-2.9
Cash and cash equivalents at the end of the period	26.6	26.6	31.7	31.7

Parent Company Statement of Changes in Equity

	Restricted equity		Unrestricted equity
Expressed in MSEK	Share capital	Statutory reserve	Other reserves	Retained earnings	Dividends	Total	Total equity
Balance at 1 January 2019	3.5	861.3	6,479.7	47,776.3	–	54,256.0	55,120.8
Total comprehensive income	–	–	–	18,885.5	–	18,885.5	18,885.5
Transactions with owners
Distributions	–	–	–	–	-4,638.7	-4,638.7	-4,638.7
Share redemption	-0.6	–	–	-14,124.2	–	-14,124.2	-14,124.8
Bonus issue (sw. fondemission)	0.6	–	–	-0.6	–	-0.6	–
Total transactions with owners	–	–	–	-14,124.8		-4,638.7 -18,763.5	-18,763.5
Balance at 31 December 2019	3.5	861.3	6,479.7	52,537.0	-4,638.7	54,378.0	55,242.8
Transfer of prior year dividends	–	–	–	-4,638.7	4,638.7	–	–
Total comprehensive income	–	–	–	2,641.9	–	2,641.9	2,641.9
Transactions with owners
Distributions	–	–	–	–	-2,867.8	-2,867.8	-2,867.8
Issuance of treasury shares	–	–	63.1	–	–	63.1	63.1
Total transactions with owners	–	–	63.1	–	-2,867.8	-2,804.7	-2,804.7
Balance at 31 December 2020	3.5	861.3	6,542.8	50,540.2	-2,867.8	54,215.2	55,080.0

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 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months	1 Jan 2019- 31 Dec 2019 12 months	1 Oct 2019- 31 Dec 2019 3 months
Revenue and other income	2,564.4	779.7	2,948.7	749.7
Operating cash flow1	1,657.6	456.6	1,537.1	378.2
CFFO	1,528.0	276.7	1,378.2	392.9
1 EBITDAX	2,140.2	708.4	1,918.4	695.5
Free cash flow	448.2	-97.5	1,271.7	153.8
Net result	384.2	303.7	824.9	155.3
Adjusted net result	280.0	86.9	252.7	78.9
Net debt	3,911.5	3,911.5	4,006.7	4,006.7
Data per share USD
Shareholders' equity per share	-6.22	-6.22	-5.63	-5.63
Operating cash flow per share1	5.83	1.61	4.87	1.33
CFFO per share	5.38	0.97	4.36	1.20
EBITDAX per share1	7.53	2.49	6.07	2.45
Free cash flow per share	1.58	-0.34	4.03	0.54
Earnings per share	1.35	1.07	2.61	0.56
Earnings per share fully diluted	1.35	1.07	2.61	0.56
Adjusted earnings per share	0.99	0.31	0.80	0.28
Adjusted earnings per share fully diluted	0.98	0.30	0.80	0.28
Dividend per share2	1.12	0.25	1.11	0.37
Number of shares issued at period end	285,924,614	285,924,614	285,924,614	285,924,614
Number of shares in circulation at period end	284,351,471	284,351,471	284,051,304	284,051,304
Weighted average number of shares for the period	284,177,604	284,351,471	315,833,140	284,051,304
Weighted average number of shares for the period fully diluted	284,830,491	284,801,383	316,551,300	284,531,709
Share price
Share price at period end in SEK	222.30	222.30	318.30	318.30
Share price at period end in USD3	27.19	27.19	34.23	34.23
Key ratios
Return on equity (%)4	–	–	–	–
Return on capital employed (%)	22	7	35	7
Net debt/equity ratio (%)4	–	–	–	–
Net debt/EBITDAX ratio1	1.8	1.8	2.1	2.1
Equity ratio (%)	-27	-27	-26	-26
Share of risk capital (%)	17	17	13	13
Interest coverage ratio	8	9	20	9
Operating cash flow/interest ratio1	11	11	16	10
Yield	4	1	3	1

1 Excludes the reported after tax accounting gain of MUSD 756.7 in 2019 on the divestment of a 2.6 percent working interest in the Johan Sverdrup project.

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

3 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.

4 As the equity at 31 December 2020 and 31 December 2019 is negative, these ratios have not been calculated.

Relevant Reconciliations of Alternative Performance Measures

EBITDAX MUSD	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months	1 Jan 2019- 31 Dec 2019 12 months	1 Oct 2019- 31 Dec 2019 3 months
Operating profit	1,420.7	488.1	1,970.7	382.5
Minus: gain from sale of assets	–	–	-756.7	–
Add: depletion of oil and gas properties	607.7	160.9	443.8	142.2
Add: exploration costs	104.9	57.6	125.6	40.9
Add: impairment costs of oil and gas properties	–	–	128.3	128.3
Add: depreciation of other tangible assets	6.9	1.8	6.7	1.6
EBITDAX	2,140.2	708.4	1,918.4	695.5

Operating cash flow MUSD	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months	1 Jan 2019- 31 Dec 2019 12 months	1 Oct 2019- 31 Dec 2019 3 months
Revenue and other income	2,564.4	779.7	2,948.7	749.7
Minus: gain from sale of assets	–	–	-756.7	–
Minus: production costs	-177.2	-38.0	-164.8	-46.2
Minus: purchase of crude oil from third parties	-217.8	-24.5	-84.3	–
Minus: current taxes	-511.8	-260.6	-405.8	-325.3
Operating cash flow	1,657.6	456.6	1,537.1	378.2

Free cash flow MUSD	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months	1 Jan 2019- 31 Dec 2019 12 months	1 Oct 2019- 31 Dec 2019 3 months
Cash flows from operating activities (CFFO)	1,528.0	276.7	1,378.2	392.9
Minus: cash flows from investing activities	-1,079.8	-374.2	-106.5	-239.1
Free cash flow	448.2	-97.5	1,271.7	153.8

Adjusted net result MUSD	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months	1 Jan 2019- 31 Dec 2019 12 months	1 Oct 2019- 31 Dec 2019 3 months
Net result	384.2	303.7	824.9	155.3
Adjusted for gain or loss from sale of assets	–	–	-756.7	–
Adjusted for impairment costs of oil and gas properties	–	–	128.3	128.3
Adjusted for unwinding of loan modification gain	99.7	70.6	41.5	10.1
Adjusted for foreign currency exchange gain or loss	-171.0	-256.2	131.7	-106.0
Adjusted for tax effects of above mentioned items	-32.9	-31.2	-117.0	-108.8
Adjusted net result	280.0	86.9	252.7	78.9

Net debt MUSD	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months	1 Jan 2019- 31 Dec 2019 12 months	1 Oct 2019- 31 Dec 2019 3 months
Bank loans	3,994.0	3,994.0	4,092.0	4,092.0
Minus: cash and cash equivalents	-82.5	-82.5	-85.3	-85.3
Net debt	3,911.5	3,911.5	4,006.7	4,006.7

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.

Board Assurance

The Board of Directors and the President and CEO certify that the financial report for the twelve months ended 31 December 2020 gives a fair view of the performance of the business, position and profit or loss of the Company and the Group, and describes the principal risks and uncertainties that the Company and the companies in the Group face.

Stockholm, 28 January 2021

Ian H. Lundin Chairman of the Board

Nick Walker President and CEO

Alex Schneiter Board member

Peggy Bruzelius C. Ashley Heppenstall Lukas H. Lundin Board member Board member Board member

Torstein Sanness Grace Reksten Skaugen Jakob Thomasen Board member Board member Board member

Cecilia Vieweg Board member

Financial Information

The Company will publish the following reports:

The three month report (January March 2021) will be published on 29 April 2021.
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 2021 Annual General Meeting (AGM) will be held on 30 March 2021 at 1 p.m. As a consequence of the global COVID-19 pandemic, the Board of Directors has decided to hold the AGM as a virtual meeting combined with proxy and postal voting options, in accordance with the temporary law on measures to facilitate the holding of general meetings (SFS 2020:198).

For further information, please contact:

VP Investor Relations Tel: +41 22 595 10 14

Edward Westropp Robert Eriksson Head of Media Communications Tel: +46 701 11 26 15 [email protected] [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
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 CET on 28 January 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-k_2021-01-28_4aa09f8e-ea89-4bbe-b0a7-5fcd2786b23f.pdf

Q YEAR END REPORT 4 2020

Highlights

Financial summary

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

Highlights

OPERATIONAL REVIEW

COVID-19 Crisis and Low Oil Price Response

Reserves and Resources

Production

Development

Johan Sverdrup Phase 2

Greater Edvard Grieg Area Tie-Back Projects

Appraisal

2020 appraisal well programme

Exploration

2020 exploration well programme

Decarbonisation Strategy and Renewable Energy Projects

Decommissioning

Licence Awards and Transactions

Health, Safety and Environment

FINANCIAL REVIEW

Result

Norwegian tax changes

Changes in the Group

Revenue and other income

Production costs

Depletion and decommissioning costs

Exploration costs

Impairment costs of oil and gas properties

Purchase of crude oil from third parties

General, administrative and depreciation expenses

Finance income

Finance costs

Share in result of joint ventures and associated company

Tax

Balance Sheet

Non-current assets

Current assets

Non-current liabilities

Current liabilities

Parent Company

Related Party Transactions

Liquidity

Contingent liabilities

Subsequent Events

Share Data

2020 dividend proposal

Remuneration

Unit Bonus Plan

Performance Based Incentive Plan

Accounting Policies

Risks and Risk Management

COVID-19 Crisis and Low Oil Price Response

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 11 – Financial liabilities

Note 13 – Trade and other payables

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

Board Assurance

Financial Information

The Company will publish the following reports:

Definitions and abbreviations

Oil related terms and measurements