Orrön Energy

Annual Report • Feb 1, 2022

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

These materials do not constitute an offer of securities for sale or a solicitation of an offer to purchase the securities described in such materials in the United States. In particular, any securities referred to in these materials have not been and will not be registered under the U.S. Securities Act of 1933 (the "Securities Act"), or under the securities laws of any state or other jurisdiction of the United States and may not be offered, sold or delivered, directly or indirectly, in or into the United States except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and in compliance with any applicable securities laws of any state or other jurisdiction of the United States. There will be no public offering of securities in the United States.

Highlights

• Board of Directors of Lundin Energy and Aker BP agreed on a combination to create the leading European independent E&P company, with completion of the transaction anticipated around mid 2022
• Record financial performance in 2021, with free cash flow generation of USD 1.6 billion and net debt reduced to USD 2.7 billion
• Board of Directors propose to increase 2021 quarterly dividend by 25 percent to USD 0.5625 per share until completion of the Aker BP transaction
• Record quarterly production for the fourth quarter of 195 Mboepd and 2022 production guidance set between 180 and 200 Mboepd
• Key projects progressing on schedule, with Johan Sverdrup Phase 2 set for first oil in the fourth quarter of 2022 and five new projects heading towards sanction within the temporary tax incentives
• Delivering growth with resource additions of 200 percent of production in 2021
• On track with Decarbonisation Plan to achieve carbon neutrality by 2023 from operational emissions

Financial summary1

	1 Jan 2021- 31 Dec 2021 12 months	1 Oct 2021- 31 Dec 2021 3 months	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months
Production in Mboepd	190.3	194.8	164.5	185.1
Revenue and other income in MUSD	5,484.7	1,621.8	2,564.4	779.7
CFFO in MUSD	3,058.0	558.1	1,528.0	276.7
Per share in USD	10.75	1.96	5.38	0.97
EBITDAX in MUSD	4,822.8	1,462.2	2,140.2	708.4
Per share in USD	16.96	5.14	7.53	2.49
Free cash flow in MUSD	1,645.5	22.6	448.2	-97.5
Per share in USD	5.79	0.08	1.58	-0.34
Net result in MUSD	493.8	121.7	384.2	303.7
Per share in USD	1.74	0.43	1.35	1.07
Adjusted net result in MUSD	795.7	253.3	280.0	86.9
Per share in USD	2.80	0.89	0.99	0.31
Net debt in MUSD	2,747.9	2,747.9	3,911.5	3,911.5

¹ All numbers in this table relate to continuing and discontinued operations combined. For a further breakdown between continuing and discontinued operations, reference is made to pages 32-33

Nick Walker, President and CEO of Lundin Energy AB, commented on the proposed combination of Lundin Energy's E&P business with Aker BP:

"We were very pleased to announce at the end of 2021, that the Board of Directors of Lundin Energy and Aker BP reached an agreement to combine the businesses to create the leading European independent E&P company. Value creation is at the heart of our business and this deal is a unique opportunity to create a world class company, with significant scale, production growth and strong free cashflow generation into the next decade. Coupled with that is a business with industry leading low costs and low carbon emissions.

"I am convinced that the combination proposal with Aker BP is a win-win outcome for both sets of shareholders, as it creates a business that is positioned to prosper through the energy transition and deliver increased and sustainable dividends. For Lundin Energy shareholders, this will deliver a significant up-front cash consideration, the opportunity to be a shareholder in the leading European E&P company and a retained interest in a renewables business that is positioned for growth. We are anticipating that the proposed combination will be completed around the middle of the year."

Nick Walker, President and CEO of Lundin Energy AB, commented on the 2021 full year results:

"I'm pleased to report that in 2021 Lundin Energy delivered record production and financial results, underpinned by continued excellent operational performance and strong oil and gas prices.

"Our world class assets continue to outperform, with industry leading production efficiency and low operating costs. We exited the year with production at just under 200 Mboepd and full year production came in above the top of our original guidance range.

"Johan Sverdrup keeps on delivering above expectations. Phase 2 of the project, which will lift production to 755 Mbopd gross, is making excellent progress and is firmly on track for first oil in the fourth quarter of 2022.

"At the Greater Edvard Grieg Area the completion of the infill drilling programme and the Solveig and Rolvsnes tie-back projects, together with a number of new projects being planned, will keep the facilities full in the long term. This is a prolific area where I see great opportunity to further extend the production plateau.

"We completed the acquisition of a further interest in the major Wisting oil development project, taking our share to 35 percent, which will help sustain the production profile of the business long term with a significant addition of low carbon emissions barrels. The Wisting development concept has been decided upon and the project is heading towards sanction at the end of 2022.

"Our growth strategy continues to deliver results with total resource additions in 2021 of 200 percent of produced volumes, supported by further reserves growth in the Greater Edvard Grieg Area and the additional interest in Wisting. I see multiple opportunities to continue to grow the business with significant potential resource upside at Johan Sverdrup, a pipeline of new projects being progressed towards development and an active exploration programme.

"At the same time, we are making great progress on our industry leading Decarbonisation Plan and are set to become carbon neutral by 2023 from operational emissions, with around 60 percent of our production already being carbon neutral. I see this as a key value differentiator for Lundin Energy.

"Financially we had a very strong year, delivering free cash flow of USD 1.6 billion, covering our 2021 dividend three times and allowing us to reduce net debt to USD 2.7 billion. I'm pleased to note that the Board of Directors is recommending a 25 percent increase in the quarterly dividend until completion of the Aker BP transaction, clearly demonstrating our commitment to long-term growth of shareholder returns.

I would like to thank all our stakeholders for their continued support over the last year, and our employees for their tremendous efforts in delivering these record results."

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

OPERATIONAL REVIEW

All the reported numbers and updates in the operational review relate to the financial year ending 31 December 2021 (reporting period) unless otherwise specified.

COVID-19 Crisis

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

Discontinued Operations

Discontinued operations represents all of Lundin Energy AB's E&P business.

Reserves and resources

Lundin Energy has 639 million barrels of oil equivalent (MMboe) of proved plus probable net reserves (2P) and 799 MMboe of proved plus probable plus possible net reserves (3P) as at 31 December 2021, as certified by an independent third party. Lundin Energy has an additional 380 MMboe net oil and gas resources, which classify as best estimate contingent resources (2C) as at 31 December 2021. The total resource base, made up of 2P reserves plus 2C contingent resources, is 1.0 Bn boe as at 31 December 2021.

Guidance and performance

	Latest 2021 Guidance	2021 Actuals	2022 Guidance
Production	180 to 195 Mboepd	190 Mboepd	180 to 200 Mboepd
Operating Cost	USD 3.0 per boe	USD 3.1 per boe	USD 3.6 per boe
Development expenditure	MUSD 770	MUSD 738	MUSD 520
Exploration and Appraisal expenditure	MUSD 325	MUSD 301	MUSD 230
Decommissioning expenditure	MUSD 15	MUSD 12	MUSD 10
Renewables Investments	MUSD 100	MUSD 79	MUSD 70

Operating costs guidance for 2022 is within the long term range of USD 3 to 4 per boe and is expected to reduce to the lower end of this guidance in 2023. The reason for the increase in operating cost guidance in 2022 compared to 2021, mainly relates to certain startup and commissioning costs for Johan Sverdrup Phase 2.

Production

Production was 190 thousand barrels of oil equivalent per day (Mboepd), at the top end of both the original guidance range of 170 to 190 Mboepd, and the updated guidance range of 180 to 195 Mboepd, released in June 2021. Fourth quarter production was 195 Mboepd, above guidance for the quarter, due to outperformance from the Edvard Grieg field.

Operating costs, net of tariff income, were USD 3.14 per boe for 2021, which was slightly above guidance. The increase was mainly driven by increased environmental taxes and higher electricity prices in the latter half of the year, a stronger NOK and somewhat offset by higher production volumes.

Production in Mboepd	1 Jan 2021- 31 Dec 2021 12 months	1 Oct 2021- 31 Dec 2021 3 months	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months
Crude oil	177.4	180.7	152.7	171.9
Gas	12.9	14.1	11.8	13.2
Total production	190.3	194.8	164.5	185.1

Production in Mboepd	WI1	1 Jan 2021- 31 Dec 2021 12 months	1 Oct 2021- 31 Dec 2021 3 months	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months
Johan Sverdrup	20%	106.3	106.6	87.6	100.3
Greater Edvard Grieg Area2	65% - 80%	72.9	77.7	63.6	72.1
Ivar Aasen	1.385%	0.6	0.6	0.8	0.7
Alvheim Area	15% - 35%	10.5	9.9	12.5	12.0
Total Production		190.3	194.8	164.5	185.1

1 Lundin Energy's working interest (WI)

2 Consisting – Edvard Grieg, Solveig and Rolvsnes EWT

The Johan Sverdrup field continues to exceed expectations, with high uptime, increased processing capacity, excellent reservoir performance and well productivities. Production from Johan Sverdrup Phase 1 has delivered in line with mid-year guidance with a production efficiency of 97 percent. In May 2021, the Phase 1 processing capacity was increased from 500 to 535 thousand barrels of oil per day (Mbopd), followed by upgrades to the water injection system to support the increased offtake. The Company's 2P reserves at year end 2021 includes for the first time a contribution from eight infill wells (previously contingent resources), extending the plateau production period. The Company recognises that there is upside resource potential in several parts of the field which will be realised through further infill drilling, optimized reservoir management and increased facilities capacity. A total of five wells were drilled and completed in 2021, with results in line with expectations. Johan Sverdrup is being operated with power supplied from shore and is one of the lowest CO2 emitting offshore fields in the world, with CO2 emissions of less than 0.1 kg per boe for the reporting period. Operating costs were USD 1.78 per boe.

Edvard Grieg has continued to perform above expectations during 2021, consistently delivering above guidance with a production efficiency of 98 percent. All three infill wells on Edvard Grieg, including the Company´s first multi-lateral and fishbone wells, were completed on time and below budget. The first well came on stream in the second quarter, while the last two came on stream in the fourth quarter. The innovative "Fishbones" technology was successfully deployed on two of the wells, resulting in a significant increase in well productivities. The 2021 reservoir performance has also resulted in an increase in the gross 2P reserves of 29 MMboe. The gross ultimate recovery for Edvard Grieg is now 379 MMboe, which is an increase of over 100 percent since the PDO.

First oil from the Solveig Phase 1 tie-back project was achieved in the third quarter of 2021. The drilling programme has been progressing as planned with four out of five wells completed and results are ahead of expectations. The Edvard Grieg hub, including the Solveig and Rolvsnes fields, has an excess of well capacity, and production will be optimized between all three fields to ensure maximum throughput from the hub. During the fourth quarter, Edvard Grieg production was prioritized over Solveig, leading to higher than expected rates from the Edvard Grieg field and lower than expected rates from the Solveig field. Drilling results and early production performance on the Solveig Phase 1 development has resulted in a reserves increase of 11 MMboe gross, representing a 20 percent increase in 2P reserves. The Rolvsnes Extended Well Test (EWT) commenced production in the third quarter and reservoir performance has continued in line with expectations. Overall, the Greater Edvard Grieg Area has a gross ultimate recovery of 450 MMboe with a 97 percent replacement ratio of its production in 2021. Operating costs for the Greater Edvard Grieg Area, net of tariff income, were USD 4.25 per boe.

Power from shore at Edvard Grieg is expected to be completed in late 2022, with the project progressing on schedule. The power cable has been installed on Edvard Grieg and laid on the seabed at Johan Sverdrup, awaiting arrival of the Phase 2 processing platform in 2022. The retirement of the existing gas turbine power generation system on the platform and installation of electric boilers to provide process heat is on schedule and is expected to be operational in late 2022. It is also estimated that the Company will benefit from a 10 percent increase in gas sales from Edvard Grieg compared to current gas sales, due to the removal of the turbine power generation.

Production from the Alvheim Area was slightly ahead of guidance with a production efficiency of 95 percent. Two infill wells came on stream during 2021, with performance ahead of expectations. First oil from the third infill well is expected in February 2022. Operating costs for the Alvheim Area were USD 7.79 per boe.

Development

Total development expenditure was MUSD 738, compared to latest guidance of MUSD 770. The reduction is due to better than expected drilling performance at Edvard Grieg and Solveig, as well as cost reductions and re-phasing of Johan Sverdrup costs into 2022.

Project	WI	Operator	Estimated gross reserves	Production start	Expected gross plateau production
Johan Sverdrup Phase 2	20%	Equinor	2.2 – 3.2 Bn boe	Q4 2022	755 Mbopd1
Solveig Phase 1	65%	Lundin Energy	69 MMboe	Sept 2021	30 Mboepd
Rolvsnes EWT	80%	Lundin Energy	3 MMboe	Aug 2021	3 Mboepd
Kobra East/Gekko (KEG)	15%	Aker BP	39 MMboe	Q1 2024	28 Mboepd
Frosk	15%	Aker BP	9 MMboe	Q2 2023	13 Mboepd
Wisting	35%	Equinor	500 MMboe	Q2 2028	150 Mboepd

1 Johan Sverdrup full field

Johan Sverdrup Phase 2

The Johan Sverdrup Phase 2 development project involves a second processing platform bridge linked to the Phase 1 field centre, subsea facilities to access the Avaldsnes, Kvitsøy and Geitungen satellite areas of the field, implementation of full field water alternating gas injection (WAG) for enhanced recovery and the drilling of 28 additional wells. The Johan Sverdrup gross field reserves are in the range of 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. In June 2021, the Company announced that the full field gross processing capacity will be increased to 755 Mbopd once Phase 2 comes on stream. The increase is a result of debottlenecking work on the Phase 2 topsides and studies to optimise the full field integrated processing and export capacity. The full field breakeven oil price for Johan Sverdrup, including past investments, is less than USD 15 per boe.

The Phase 2 capital expenditure is estimated at gross NOK 41 billion (nominal), which is unchanged from the Phase 2 PDO estimate in 2019. The three modules that constitute the second processing platform topsides were successfully assembled in May 2021, the Jacket for the second processing platform was successfully installed offshore in June 2021 and the new module on the existing riser platform was successfully installed offshore in July 2021. The operation to install the second processing platform topsides on the jacket is planned for March 2022. The subsea facilities and flowlines installation work is progressing as per schedule and will be completed early 2022, with drilling operations on the subsea wells having commenced in January 2022. First oil remains on schedule for fourth quarter 2022, with project progress now approximately 70 percent complete.

Greater Edvard Grieg Area Tie-Back Projects

Solveig Phase 1 came on stream in September 2021, on schedule and is the first Edvard Grieg subsea tie-back development. Drilling of the Phase 1 development wells are almost complete, with three production wells and one injection well completed in 2021 and the final water injection well scheduled for completion in the first quarter of 2022. The capital cost for the Phase 1 development is below the PDO estimate of MUSD 810 gross, with a breakeven oil price below USD 20 per boe.

The Rolvsnes EWT project, has been developed through a 3 km 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 of the Rolvsnes full field development and it holds important information on the general basement potential for the Utsira high. The project has been developed in conjunction with the Solveig project, to take advantage of contracting and implementation synergies. The project achieved first oil, on schedule and below budget, in August 2021 with reservoir performance in line with expectations.

Wisting

The Wisting project is scheduled to be one of the next Barents Sea production hubs and will be a significant contributor to sustaining the Company's long term production profile. With the acquisition of a further 25 percent working interest announced on 28 October 2021, the Company's working interest in the project has increased to 35 percent and will add material pre-development resources in a strategic core area for the Company, with significant surrounding prospectivity. In November 2021, the project development concept was approved by the licence partners, with the project on track for PDO submission by end 2022, allowing the project to benefit from the temporary tax incentives established by the Norwegian Government in June 2020. The Wisting project has strong economics, and the development plan is aligned with Lundin Energy's Decarbonisation Plan, with a power from shore solution being matured as part of the PDO. In addition, in December 2021, Lundin Energy concluded a cooperation agreement with Equinor for the Wisting development, whereby Equinor will retain operatorship of the Wisting development into the operations phase. The cooperation agreement also gives the Company operatorship in the exploration licences surrounding Wisting (PL1133 and PL1134), including an increase in working interests to 35 percent. The agreement also covers licences applied for in the 2021 APA round. It has also been agreed that employees from the Company will be placed in key technical and operational positions within the Wisting project. This agreement further strengthens the relationship between Equinor and Lundin Energy and sets out a strong collaboration for exploration and operations in what will be the next Barents Sea production hub.

Kobra East/Gekko (KEG)

In June 2021, the PDO for the joint development of the two discoveries Kobra East and Gekko was submitted to the Norwegian Ministry of Petroleum and Energy and was approved in January 2022. The development will be a subsea tie-back to the Alvheim FPSO and phase one of the development will include four tri-lateral production wells targeting the oil zones of the two discoveries. Phase two of the development consists of a gas production well targeting the gas cap at Gekko, which will be drilled at a later stage once gas processing capacity is available on the Alvheim FPSO. Drilling operations are expected to commence in early 2023, with first oil planned in the first quarter of 2024. Total gross 2P reserves for the project amount to 39 MMboe and the development will provide gross peak production of approximately 28 Mboepd. This project will be developed under the Norwegian temporary tax regime and has a breakeven oil price of less than USD 30 per boe.

Frosk

In September 2021, the PDO for the development of the Frosk discovery was submitted to the Norwegian Ministry of Petroleum and Energy. The development will be a subsea tie-back to the Alvheim FPSO through the existing Bøyla Manifold. The development includes the drilling of two new wells. Drilling operations are expected to commence in 2022, with first oil planned in the first half of 2023. Total gross reserves for the project amount to approximately 9 MMboe and the development will provide gross peak production of approximately 13 Mboepd, with a breakeven oil price of less than USD 25 per boe.

Exploration and Appraisal

The 2021 exploration and appraisal programme consisted of eight wells. Discoveries were made in the Segment D of the Solveig field and at Lille Prinsen. The exploration and appraisal expenditure guidance for 2021 was updated due to increased scope at the Segment D, Iving, Lille Prinsen wells and the additional 25 percent working interest in Wisting, effective from 1 January 2021. Total exploration and appraisal expenditure for 2021 was MUSD 301 which is below the updated guidance of MUSD 325.

2021 Exploration and Appraisal Well Programme

Licence	Operator	WI	Well	Spud Date	Status
PL359	Lundin Energy	65%	Segment D	February 2021	Oil discovery
PL722	Equinor	20%	Shenzhou	April 2021	Dry
PL820S	MOL	41%	Iving (2 wells)	May 2021	Non-commercial oil discovery
PL167	Lundin Energy	40%	Lille Prinsen	July 2021	Oil discovery
PL981	Lundin Energy	60%	Merckx	September 2021	Dry
PL976	Lundin Energy	40%	Dovregubben	September 2021	Dry
PL1041	Aker BP	15%	Lyderhorn	October 2021	Non-commercial oil discovery
PL886	Lundin Energy	60%	Melstein	January 2022	Dry

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

In July 2021, a two-well appraisal drilling campaign was completed on the Iving discovery located in the Central North Sea close to the Balder and Ringhorne fields. The results were below expectation and the project has been assessed as non-commercial.

In September 2021, the exploration and appraisal programme on Lille Prinsen in PL167, located on the Utsira High in the Norwegian part of the North Sea, was successfully completed. The wells confirmed a combined gross resource range of 12 to 60 MMboe. A development solution is currently being matured, aiming for project sanction in 2022.

In 2020, the Norwegian Government introduced temporary tax incentives aiming to increase activity on the Norwegian Continental Shelf, which applies to projects with PDO's submitted before the end of 2022. These tax incentives significantly improve project economics, and the Company has taken steps to accelerate activities for the potential projects, which could benefit from this opportunity. Further projects to be de-risked include Solveig Phase 2 (incorporating the Segment D discovery) and Rolvsnes Full Field, both of which require production experience to mature development solutions. At both Lille Prinsen and Trell and Trine, the field development and concept select studies are progressing well with an aim to submit the PDO's for both projects before the end of 2022.

Decarbonisation

Decarbonisation is a key strategic pillar for Lundin Energy and a significant differentiator for the business. The decarbonisation plan is composed of four pillars – reducing operational emissions, powering key assets from shore, investing in renewable power to replace net electricity usage and investments in natural carbon capture projects to neutralise residual emissions. A critical step towards carbon neutrality will be the electrification of the Edvard Grieg platform, which is being executed in parallel with the Johan Sverdrup Phase 2 development and will be operational in late 2022. Carbon emissions were 2.9 kg of CO2 per boe in the reporting period, which is well within the Company's 2021 target of less than 4 kg of CO2 per boe. On completion of the electrification of Edvard Grieg, the Company's average net carbon intensity is expected to be approximately 1 kg CO2 per boe, over fifteen times better than the industry average. Considering this, in September 2021, the decision was taken to accelerate decarbonisation by two years to achieve carbon neutrality for operational emissions from 2023.

In January 2021, the Company signed a partnership with Land Life Company B.V., to invest MUSD 35 in high quality re-forestation projects to plant approximately seven million trees between 2021 and 2025, capturing approximately 2.5 million tonnes of CO2 . During the reporting period, approximately 480,000 trees were planted in Spain and Ghana.

In September 2021, Lundin Energy signed a partnership with EcoPlanet Bamboo WA ll. The Company will invest MUSD 9 in sustainable bamboo plantations where over 1 million bamboo clumps will be planted on degraded land between 2022-2024, capturing approximately 1.7 million tonnes of CO2 over 10 years. All of Lundin Energy's carbon capture projects will transfer to Aker BP after completion of the proposed combination.

In November 2021, Lundin Energy was included in the S&P Global Dow Jones Sustainability Europe Index (DJSI) for the first time, and ranked as one of the top three companies in Europe within its industry. The DJSI comprises European ESG leaders and represents the top 20 percent of ranked companies from the largest 600 companies in the S&P Global Broad Market Index.

Certified Carbon Neutrally Produced Crude Oil Sale

In April 2021, Lundin Energy announced that it had sold a cargo of certified carbon neutrally produced Edvard Grieg crude to Saras S.p.A, the first such cargo in the world to have been traded and a significant step forward for the international oil market, in terms of a barrel of crude oil trading on the merits of its carbon emissions. Lundin Energy's Edvard Grieg field was the first oil field in the world to be independently certified by Intertek Group plc (Intertek), under its CarbonClearTM certification. The field is certified as low carbon at 3.4 kg of CO2 e per boe, including exploration, development and production.

Following the success of the first certified, carbon neutrally produced barrels at Edvard Grieg, in June 2021, Lundin Energy announced that all future barrels of oil the Company sells from the Johan Sverdrup field will be certified as carbon neutrally produced under the CarbonZeroTM standard. The field has been independently certified at 0.4 kg CO2 e per boe, approximately 40 times better than the world average. The first carbon neutrally produced cargo from Johan Sverdrup was sold to GS Caltex, Korea in June 2021.

In order to supply a carbon neutrally produced barrel, residual emissions for both the Edvard Grieg and Johan Sverdrup fields were compensated through high quality, natural carbon capture projects, certified by the Verified Carbon Standard (VCS) and independently certified by Intertek. Almost 60 percent of the Company's current net production is certified as carbon neutrally produced. Carbon neutrally produced cargo sales have continued during the period, adding competitive advantage to our marketing efforts and it is management's strong belief that as the market for carbon neutrally produced crudes matures, a premium per barrel will be realised, adding significant value potential.

Decommissioning

The Brynhild field ceased production in 2018 and the decommissioning plan was approved by Norwegian and UK authorities in 2020. Abandonment of the four Brynhild subsea wells was completed in 2020 and the marine campaign for removal of the subsea facilities was completed in July 2021. The Gaupe field ceased production in 2018 and preparation of the decommissioning plan for the field is ongoing, with decommissioning activities expected to commence in 2023. Following completion of Brynhild and Gaupe decommissioning, the Company has no further planned decommissioning spend until around 2035. The decommissioning expenditure in 2021 was MUSD 12.

Licence Awards and Transactions

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

In February 2021, Lundin Energy entered into a sales and purchase agreement with Aker BP involving the acquisition of a six percent working interest in licenses PL036E, PL036F, PL102H, PL102F, PL102D and PL102G which includes the Trell and Trine Unit. The transaction included the sale of a five percent working interest in PL869 and a 15 percent working interest in PL1041. In January 2022 Lundin Energy entered into a sales and purchase agreement with MOL involving the acquisition of a ten percent working interest in licenses PL102F and PL102G, which includes the Trell discovery and Trell Nord prospect, equivalent to 6.84 percent in the Trell and Trine Unit, bringing Lundin Energy's total working interest to 12.84 percent in the Unit.

In May 2021 Lundin Energy entered into a sales and purchase agreement with One-Dyas involving the divestment of a ten percent working interest in PL976.

In June 2021, Lundin Energy was awarded two licenses in the 25th licensing round.

In October 2021, Lundin Energy entered into a purchase agreement with OMV Norge AS involving the acquisition of an additional 25 percent working interest in license PL537, which includes the Wisting discovery, bringing Lundin Energy's working interest to 35 percent. The transaction, which completed in December 2021, is effective from January 2021 and adds estimated net contingent resources of approximately 131 MMboe for a cash consideration of MUSD 320. There is a contingency arrangement also in place depending on an increase or reduction in final development capital spend, the benefit of which is shared between the parties.

Lundin Energy increased its interests in PL917 from 20 percent to 40 percent and acquired a 20 percent interest in PL956 and a 10 percent interest in PL985, through two transactions, one with ConocoPhillips and one with Vår Energi. PL917 contains interesting follow up potential to the King discovery that was made in the neighbouring licence. An exploration well is planned to be drilled on the Ringhorne Ty prospect in 2023 and PL985 contains attractive prospectivity north of the PL956.

In January 2022, the Company was awarded 10 licenses in the 2021 APA round, of which five are as operator.

The Company currently holds 97 licenses in Norway.

Health, Safety and Environment

During the reporting period, there were no lost time incidents, resulting in a Lost Time Incident Rate of zero per million hours worked for 2021. The Total Recordable Incident Rate for the year was 2.14 per million hours worked. There were no process safety or material environmental incidents during the reporting period.

Continuing operations

Continuing operations represents Lundin Energy AB's renewable energy portfolio of onshore assets in the Nordics. In addition, the Company will retain certain non-Norwegian potential liabilities related to past operations.

Renewable Energy generation portfolio

In April 2021, the Company completed a transaction with OX2 AB (OX2) to acquire a 100 percent interest in the Karskruv onshore wind farm project in southern Sweden. The construction works on the wind farm have already commenced and are progressing on schedule with the facility planned to be operational in late 2023 with production of an estimated 290 GWh per annum, from 20 onshore wind turbines. The total investment in Karskruv, including the acquisition cost, will amount to MEUR 130 with the majority of the spend occurring in 2022 and 2023 and the project will be cash flow positive from 2024. Construction and commissioning of the second phase of the Leikanger hydropower project in Norway was completed in March 2021 and is now operational at full capacity. The project works are progressing well on the Metsälamminkangas (MLK) wind farm in Finland, with most of the construction work completed. Power has already started to be generated with the first wind turbine online in early October. Commercial handover of the wind farm to the Company was originally planned for late Q4 2021 but has been pushed into the first half of 2022 with final commissioning taking longer than first anticipated. Lundin Energy is covered by liquidated damages in the period up to commercial handover for the entire delay period.

The Company has now committed to three renewable projects, with a combined net power generation capacity of around 600 GWh per annum from late 2023 and these investments will remain in the Company after the combination with Aker BP with an aim to become a platform for growth. Renewable energy expenditure for 2021 was MUSD 79 compared to the guidance of MUSD 100, due to the delayed completion of the MLK project.

FINANCIAL REVIEW

Aker BP transaction

On 21 December 2021, Lundin Energy announced that it had entered into an agreement (the transaction) with Aker BP whereby Aker BP will absorb Lundin Energy's E&P business through a cross-border merger in accordance with Norwegian and Swedish law. Before completion of the cross-border merger, the shares in the company holding Lundin Energy's E&P business will be distributed to Lundin Energy shareholders. Consequently Lundin Energy presented its E&P business as discontinued operations in the consolidated Income Statement and presented the asset and liabilities associated with the E&P business as assets and liabilities held for distribution in the consolidated Balance Sheet. Once the transaction with Aker BP is completed, the renewable business, which is reported as continuing operations, will be debt free and have a cash balance of MUSD 130, to cover capital expenditure and other working capital items. The renewable business is expected to be free cash flow positive from late 2023, when the renewable portfolio has been fully built out and all projects are operational.

Under the agreement with Aker BP, in exchange for Lundin Energy's E&P business, shareholders will be entitled to a cash consideration totaling BUSD 2.22 (approximately SEK 71.0 per share after conversion from USD at 20 December 2021 exchange rates), 271,910,019 Aker BP shares (representing 0.951 Aker BP share for every 1 Lundin Energy share, equivalent to SEK 279.3 per share at 20th December 2021) and will retain their existing shareholding in Lundin Energy and its renewables business (detail on business plan, management and governance will be published by 25 February 2022). Accordingly following the completion of the transaction, (subject to shareholder approval at the Company's AGM on 31 March 2022, shareholder approval by Aker BP's General Meeting and receipt of necessary governmental approvals), the shareholders of Lundin Energy will hold 43 percent of the total shares and votes of Aker BP, (based on a total of 360,113,509 shares and votes in Aker BP).

Result

The numbers in this financial review section refer to the continuing and discontinued operations combined unless stated otherwise. For a further breakdown between continuing and discontinued operations of the key financial data, reference is made to pages 32-33.

The Company generated record high revenue and other income for the year of MUSD 5,484.7 (MUSD 2,564.4) with the increase compared to the comparative period mainly driven by higher sales volumes and higher oil and gas prices. Sales volumes increased by 19 percent compared to the comparative period caused by better production performance, inventory movements and overlift movements during the year. Realised prices per boe increased by 85 percent compared to the comparative period with realised gas and NGL prices for the year being almost four times higher compared to 2020. Realised gas and NGL prices for the fourth quarter were around USD 150/boe which is almost five times higher compared to the fourth quarter 2020.

The net result for the year amounted to MUSD 493.8 (MUSD 384.2), representing earnings per share of USD 1.74 (USD 1.35). Net result was driven by the higher revenue and other income and negatively impacted by higher cost of sales, a largely non-cash foreign currency exchange loss during the year of MUSD 216.3 (MUSD -171.8) and higher income tax charges. Adjusted net result for the year amounted to MUSD 795.7 (MUSD 280.0), representing adjusted earnings per share of USD 2.80 (USD 0.99). Adjusted net result separates out the effects of loan modification gains, foreign currency exchange results, ineffective interest rate hedge contracts and other non recurring finance costs, 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 253.3 (MUSD 86.9) and represented a record high quarterly adjusted net result for the Company.

The Company generated earnings before interest, tax, depletion, amortization and exploration expenses (EBITDAX) for the year of MUSD 4,822.8 (MUSD 2,140.2) representing EBITDAX per share of USD 16.96 (USD 7.53), with the increase compared to the comparative period mainly caused by the higher sales volumes and higher oil prices. EBITDAX for the fourth quarter amounted to MUSD 1,462.2 (MUSD 708.4) and represented a record high quarterly EBITDAX for the Company. Cash flow from operating activities (CFFO) for the year amounted to MUSD 3,058.0 (MUSD 1,528.0), representing CFFO per share of USD 10.75 (USD 5.38) with the increase compared to the comparative period, again impacted by higher sales volumes and higher oil prices, but negatively impacted by working capital changes and higher tax payments during the year. CFFO for the fourth quarter amounted to MUSD 558.1 (MUSD 276.7). Free cash flow for the year amounted to MUSD 1,645.5 (MUSD 448.2), representing free cash flow per share of USD 5.79 (USD 1.58), with the increase compared to the comparative period mainly impacted by higher CFFO partly offset by higher investments in oil and gas properties. Free cash flow for the fourth quarter amounted to MUSD 22.6 (MUSD -97.5) and included the cash consideration of MUSD 320 for the acquisition of an additional 25% working interest in the Wisting oil discovery. Driven by the strong free cash flow generation during the year, the Company reduced its net debt from MUSD 3,911.5 as per the end of 2020 to MUSD 2,747.9 as per the end of 2021, a reduction of approximately BUSD 1.2.

Changes in the Group

In April 2021, the Company completed a transaction with OX2 AB (OX2) to acquire a 100 percent interest in the Karskruv onshore wind farm project in southern Sweden. The wind farm will become operational in late 2023 and will produce an estimated 290 GWh per annum, from 20 onshore wind turbines. The total investment in Karskruv, including the acquisition cost, will amount to MEUR 130 with the majority of the spend occurring in 2022 and 2023.

In October 2021, Lundin Energy entered into a sales and purchase agreement for the acquisition of OMV Norge's 25 percent working interest in license PL537, which contain the Wisting discovery. The transaction increased the Company's working interest to 35 percent. The transaction involved a cash consideration payable to OMV Norge of MUSD 320.0 and was completed in December 2021, with economic effect from 1 January 2021. The transaction was accounted for as an asset acquisition.

On 21 December 2021, Lundin Energy announced the transaction with Aker BP as mentioned above resulting in the E&P business presented as discontinued operations in the consolidated Income Statement and the asset and liabilities associated with the E&P business presented as assets and liabilities held for distribution in the consolidated Balance Sheet.

Revenue and other income

Revenue and other income for the year amounted to MUSD 5,484.7 (MUSD 2,564.4) and was comprised of net sales of oil and gas and other revenue as detailed in Note 4. Revenue and other income fully related to the discontinued operations.

Net sales of oil and gas for the year amounted to MUSD 5,452.9 (MUSD 2,533.2). The average price achieved by Lundin Energy for a barrel of oil equivalent (boe) from own production, amounted to USD 71.01 (USD 38.35) and is detailed in the following table. The average gas price achieved during the fourth quarter by Lundin Energy for a barrel of oil equivalent (boe) amounted to USD 204.21 (USD 33.43), more than six times higher compared to the fourth quarter of 2020. The average Dated Brent price for the year amounted to USD 70.91 (USD 41.84) per barrel and USD 79.76 (USD 44.16) for the fourth quarter.

Net sales of oil and gas from own production for the year are detailed in Note 6 and were comprised as follows:

Sales from own production Average price per boe expressed in USD	1 Jan 2021- 31 Dec 2021 12 months	1 Oct 2021- 31 Dec 2021 3 months	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months
Crude oil sales
- Quantity in Mboe	65,381.1	16,536.5	54,263.6	15,441.2
- Average price per bbl	69.36	76.98	39.96	44.72
Gas and NGL sales
- Quantity in Mboe	6,281.8	1.797.8	6,013.2	1,781.5
- Average price per boe	88.10	150.23	23.80	32.48
Total sales
- Quantity in Mboe	71,662.9	18,334.3	60,276.8	17,222.7
- Average price per boe	71.01	84.16	38.35	43.45

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

The sales of crude oil from third party activities for the year amounted to MUSD 364.4 (MUSD 221.5) 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 31.8 (MUSD 31.2) and mainly included tariff income of MUSD 21.6 (MUSD 23.2), which is due to net income from Ivar Aasen tariffs paid to Edvard Grieg. Other income for the year also included a gain of MUSD 2.0 (MUSD 0.8) relating to short-term oil price derivatives.

Production costs

Production costs including under/over lift movements and inventory movements for the year amounted to MUSD 265.4 (MUSD 177.2) and are detailed in Note 5. Production costs fully related to the discontinued operations. The total production cost per barrel of oil equivalent produced is detailed in the table below:

	1 Jan 2021- 31 Dec 2021	1 Oct 2021- 31 Dec 2021	1 Jan 2020- 31 Dec 2020	1 Oct 2020- 31 Dec 2020
Production costs	12 months	3 months	12 months	3 months
Cost of operations
- In MUSD	167.5	51.5	134.5	32.6
- In USD per boe	2.41	2.88	2.24	1.92
Tariff and transportation expenses
- In MUSD	71.9	20.9	50.7	14.3
- In USD per boe	1.03	1.16	0.84	0.84
Operating costs
- In MUSD	239.4	72.4	185.2	46.9
- In USD per boe1	3.44	4.04	3.08	2.76
Change in under/over lift position
- In MUSD	7.9	3.6	-2.7	1.2
- In USD per boe	0.11	0.20	-0.05	0.06
Change in inventory position
- In MUSD	11.5	0.3	-11.2	-11.6
- In USD per boe	0.17	0.02	-0.19	-0.68
Other
- In MUSD	6.5	1.6	5.9	1.5
- In USD per boe	0.09	0.09	0.10	0.09
Production costs
- In MUSD	265.4	78.0	177.2	38.0
- In USD per boe	3.81	4.35	2.94	2.23

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 3.44 (USD 3.08) per barrel is reduced to USD 3.14 (USD 2.69) when tariff income is netted off. The operating cost for the fourth quarter of USD 4.04 (USD 2.76) per barrel is reduced to USD 3.81 (USD 2.44) when tariff income is netted off.

The total cost of operations for the year amounted to MUSD 167.5 (MUSD 134.5) and the total cost of operations excluding operational projects amounted to MUSD 160.2 (MUSD 127.8). The cost of operations per barrel for the year amounted to USD 2.41 (USD 2.24) including operational projects and USD 2.31 (USD 2.12) excluding operational projects. The higher unit costs compared to the comparative period are mainly caused by higher electricity prices and environmental taxes in the latter half of the year and a stronger Norwegian Krone which is partly offset by higher production volumes.

Tariff and transportation expenses for the year amounted to MUSD 71.9 (MUSD 50.7) or USD 1.03 (USD 0.84) per boe. The increase on a per barrel basis compared to the comparative period is caused by a stronger Norwegian Krone and an increase in a few crude and gas unit tariffs.

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 7.9 (MUSD -2.7) 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 11.5 (MUSD -11.2) in the year due to a cargo in transit at the end of 2020 that was sold in early 2021. Sales quantities and production quantities are detailed in the table below:

Change in over/underlift position In Mboepd	1 Jan 2021- 31 Dec 2021 12 months	1 Oct 2021- 31 Dec 2021 3 months	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months
Production volumes	190.3	194.8	164.5	185.1
Inventory movements	1.7	–	-1.7	-6.8
Production volumes including inventory movements	192.0	194.8	162.8	178.3
Sales volumes from own production	196.3	199.3	164.7	187.2
Change in over/underlift position	-4.3	-4.5	-1.9	-8.9

Other costs for the year amounted to MUSD 6.5 (MUSD 5.9) and related to the business interruption insurance.

Depletion and decommissioning costs

Depletion and decommissioning costs for the year amounted to MUSD 703.0 (MUSD 607.7), at an average rate of USD 10.12 (USD 10.09) per boe and fully related to the discontinued operations. Depletion costs on a per barrel basis compared to the comparative period were stable consisting of a lower depletion rate per barrel in Norwegian Krone as a result of increased reserves in Norway offset by a stronger Norwegian Krone as the depletion rate per boe is calculated in Norwegian Krone. Following the announcement of the Aker BP transaction on 21 December 2021 and the subsequent reclassification of the E&P business as assets and liabilities held for distribution in the consolidated Balance Sheet, the company ceased depletion as per IFRS5 from the date of the deal announcement on 21 December 2021.

Exploration costs

Exploration costs expensed in the income statement for the year amounted to MUSD 258.1 (MUSD 104.9) and fully related to the discontinued operations. Exploration and appraisal costs are capitalised as they are incurred. When exploration and appraisal drilling is unsuccessful, the capitalised costs are expensed. All capitalised exploration costs are reviewed on a regular basis and are expensed when facts and circumstances suggest that the carrying value of an exploration and evaluation asset may exceed its recoverable amount.

Purchase of crude oil from third parties

Purchase of crude oil from third parties for the year amounted to MUSD 361.7 (MUSD 217.8) and related to crude oil purchased from outside the Group. Purchase of crude oil from third parties and fully related to the discontinued operations.

General, administrative and depreciation expenses

The general administrative and depreciation expenses for the year amounted to MUSD 41.9 (MUSD 36.1) of which MUSD 19.4 (MUSD 16.4) related to the continuing operations and MUSD 22.5 (MUSD 19.7) to the discontinued operations. The general administrative and depreciation expenses included a charge of MUSD 6.1 (MUSD 4.8) in relation to the Group's long-term incentive plans (LTIP), see also Remuneration section on page 15. Fixed asset depreciation expenses for the year amounted to MUSD 7.1 (MUSD 6.9).

Finance income

Finance income for the year amounted to MUSD 3.8 (MUSD 173.1) of which MUSD 2.6 (MUSD 0.5) related to the continuing operations and MUSD 1.2 (MUSD 172.6) to the discontinued operations and is detailed in Notes 1 and 7.

Finance costs

Finance costs for the year amounted to MUSD 473.0 (MUSD 319.4) of which MUSD 0.2 (MUSD 0.9) related to the continuing operations and MUSD 472.8 (MUSD 318.5) to the discontinued operations and is detailed in Notes 2 and 8.

The net foreign currency exchange loss for the year amounted to MUSD 216.3 (MUSD -171.8). 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 22.9 (MUSD 65.6). As a result of the Aker BP transaction, part of the outstanding foreign currency exchange instruments are no longer considered effective under hedge effectiveness testing resulting in an additional non-cash charge to the income statement of MUSD 15.5 based on the marked-to-market foreign exchange rates as of 31 December 2021.

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

Interest expenses for the year amounted to MUSD 52.5 (MUSD 104.4) and represented the portion of interest charged to the income statement. An additional amount of interest of MUSD 23.6 (MUSD 25.8), mainly associated with the funding of the Norwegian development projects was capitalised during the year. The total interest expenses for the year decreased compared to the comparative period as a result of a lower LIBOR rate, a lower interest rate margin over LIBOR following the refinancing in December 2020 and a lower average outstanding debt relative to the comparative period.

The result on interest rate hedges for the year amounted to a loss of MUSD 122.0 (MUSD 44.5), as a result of the lower LIBOR rate, which included a MUSD 71.0 charge to the income statement in relation to interest rate hedge contracts no longer considered effective under hedge effectiveness testing and of which MUSD 53.4 was non-cash. The Company issued USD 2 billion of Senior Notes in June 2021 with a fixed interest rate and used the net proceeds, in combination with cash on hand, to repay USD 2 billion of the corporate credit facility term loans with a floating interest rate. The company repaid a further USD 0.3 billion of the corporate credit facility in November 2021 and as a result, part of the outstanding interest rate hedge contracts are no longer effective under hedge effectiveness testing. As a result of the Aker BP transaction, additional outstanding interest rate hedge contracts are no longer considered effective under hedge effectiveness testing.

The amortisation of the deferred financing fees for the year amounted to MUSD 35.5 (MUSD 37.6) and related to the expensing of the fees incurred in establishing the credit facility over the period of usage of the facility. In addition, the unamortised portion of the capitalised financing fees incurred in relation to the repaid USD 2.3 billion corporate credit facility term loans were expensed during the year. As a result of the Aker BP transaction, additional capitalised financing fees were expensed during the year. Following the successful refinancing in December 2020, unamortised capitalised financing fees in relation to the reserve-based lending facility, the MUSD 160 revolving credit facility and the MUSD 340 unsecured corporate facility were expensed during the comparative period.

Loan facility commitment fees for the year amounted to MUSD 7.2 (MUSD 11.5) and related to commitment fees for the undrawn amounts under the revolving corporate credit facility which was undrawn at the end of the year.

The unwinding of the loan modification gain in the comparative period amounted to MUSD 99.7 and related to the expensing of the accounting gain from the re-negotiated improved borrowing terms in 2018 for the reserve-based lending facility over the period of usage of the facility. Following the successful refinancing in December 2020, the remaining portion of the capitalised loan modification gain was expensed during the comparative period.

Share in result of joint ventures

Share in result of joint ventures for the year amounted to MUSD 0.9 (MUSD -0.1) and related to the 50 percent non-operated interest in the Leikanger hydropower project in Norway. Share in result of joint ventures fully related to the continuing operations.

Tax

The overall tax charge for the year amounted to MUSD 2,892.5 (MUSD 890.1) of which MUSD – (MUSD 1.0) related to the continuing operations and MUSD 2,892.5 (MUSD 889.1) to the discontinued operations. The tax charge relating to the discontinued operations is detailed in Note 9.

The current tax charge for the year amounted to MUSD 2,562.8 (MUSD 511.8) 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 paid tax installments in Norway during the year amounted to MUSD 1,387.3, 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 end 2020, from MUSD 444.4 to MUSD 1,573.7.

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

The Norwegian Government has further proposed to revise the SPT system as of 2022, replacing the rules on depreciation and uplift with immediate investment expensing (cash-flow tax), though the combined tax rate for corporation tax and SPT will remain unchanged at 78%. These changes have no implication for the rules for the temporary changes described above.

The deferred tax charge for the year amounted to MUSD 329.7 (MUSD 378.3) 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 decreased for the year due to the temporary tax changes for the Special Petroleum Tax in Norway enacted in June 2020, 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 loss and the expensed interest rate hedge contracts which are no longer considered effective under hedge effectiveness testing. The effective tax rate on the adjusted net results for the year amounted to 78 percent.

Balance Sheet - Continuing operations

Non-current assets

Renewable energy properties amounted to MUSD 31.5 (MUSD –) and related to the fully consolidated 100 percent interest in the Karskruv onshore wind farm project in southern Sweden.

Investments in joint ventures amounted to MUSD 108.7 (MUSD 110.6) and related to the 50 percent interest in the Metsälamminkangas (MLK) wind farm project in Finland and the 50 percent interest in the Leikanger hydropower project in Norway which are not fully consolidated and reported as investments in joint ventures.

Receivables from joint ventures amounted to MUSD 35.1 (MUSD –) and related to long term interest bearing loans provided to the joint ventures holding the investments in the Metsälamminkangas (MLK) wind farm project in Finland and the Leikanger hydropower project in Norway.

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

Renewables investments In MUSD	1 Jan 2021- 31 Dec 2021 12 months	1 Oct 2021- 31 Dec 2021 3 months	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months
Karskruv Windfarm – Sweden	30.9	–	–	–
MLK Windfarm – Finland	41.0	1.3	46.3	11.1
Leikanger Hydropower – Norway	1.2	0.6	49.8	4.9
Natural Carbon Capture	5.6	1.9	–	–
Renewables investments	78.7	3.8	96.1	16.0

The Natural Carbon Capture projects as included in the table will be part of the discontinued operations.

Current assets

Assets held for distribution amounted to MUSD 7,468.2 (MUSD –) and is detailed in Note 3.

Trade and other receivables amounted to MUSD 5.3 and related mainly to working capital balances within the continuing operations.

Receivable from discontinued operations amounted to MUSD 128.6 (MUSD –) and equals the dividend liability as approved by the AGM held on 30 March 2021 in Stockholm which is paid in quarterly installments. The discontinued operations have committed to fund the dividend and this receivable was settled early 2022 when the fourth quarterly dividend was paid to the shareholders.

Cash and cash equivalents amounted to MUSD 130.0 (MUSD 82.5) and related to the cash balance which will be retained by the continuing operations to cover capital expenditure and other working capital items. The renewable business is expected to be free cash flow positive from late 2023, when the renewable portfolio has been fully built out and all projects are operational.

Current liabilities

Liabilities held for distribution amounted to MUSD 9,194.0 (MUSD –) and is detailed in Note 3.

Dividends amounted to MUSD 128.6 (MUSD 72.3) and related to the cash dividend approved by the AGM held on 30 March 2021 in Stockholm, paid in quarterly installments.

Trade and other payables amounted to MUSD 4.2 and related mainly to working capital balances within the continuing operations.

Balance Sheet - Discontinued operations

All balance sheet items relating to the discontinued operations have been reclassified as assets held for distribution and liabilities held for distribution as detailed in Note 3. Comparative numbers have not been reclassified under IFRS and therefore not included in Note 3.

Assets held for distribution

Oil and gas properties amounted to MUSD 6,222.2 and are detailed in Note 10. Oil and gas properties included Right of use assets as per IFRS16 and amounted to MUSD 5.3 relating to a drilling rig recognised under IFRS 16 during the year.

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

Development expenditure In MUSD	1 Jan 2021- 31 Dec 2021 12 months	1 Oct 2021- 31 Dec 2021 3 months	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months
Norway	738.4	176.1	639.8	148.4
Development expenditure	738.4	176.1	639.8	148.4

Development expenditure of MUSD 738.4 (MUSD 639.8) was incurred in Norway during the year, primarily on the Johan Sverdrup, Edvard Grieg, Solveig and Rolvsnes fields. In addition an amount of MUSD 23.1 (MUSD 25.8) of interest was capitalised.

Exploration and appraisal expenditure In MUSD	1 Jan 2021- 31 Dec 2021 12 months	1 Oct 2021- 31 Dec 2021 3 months	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months
Norway	300.6	58.4	152.9	67.1
Exploration and appraisal expenditure	300.6	58.4	152.9	67.1

Exploration and appraisal expenditure of MUSD 300.6 (MUSD 58.4) was incurred in Norway during the year, primarily for the exploration and appraisal wells as summarised on page 6.

Other tangible fixed assets amounted to MUSD 42.0 and are detailed in Note 11. Other tangible fixed assets included Right of use assets as per IFRS 16 and amounted to MUSD 27.2.

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

Financial assets amounted to MUSD 12.7 and are detailed in Note 12. 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.

Inventories amounted to MUSD 55.7 and included both well supplies and hydrocarbon inventories.

Trade and other receivables amounted to MUSD 657.2 and are detailed in Note 13. Trade receivables, which are all current, amounted to MUSD 523.9. Underlift amounted to MUSD 23.2 and was attributable to an underlift position on the producing fields, mainly relating to oil from the Edvard Grieg field. Joint operations debtors relating to various joint venture receivables amounted to MUSD 36.2. Prepaid expenses and accrued income amounted to MUSD 68.7 and included MUSD 44.2 related to cargo liftings during the year not yet invoiced and prepaid operational and insurance expenditure. Other current assets amounted to MUSD 5.2.

Derivative instruments amounted to MUSD 18.5 and related to the marked-to-market valuation of outstanding currency hedge contracts.

Current tax assets amounted to MUSD 9.7 and related to payments of tax installments outside Norway during the year and are expected to be recovered in the future.

Cash and cash equivalents amounted to MUSD 322.1. Cash balances are mainly held to meet ongoing operational funding requirements as well as to provide headroom liquidity.

Liabilities held for distribution

Bonds amounted to MUSD 1,979.9 and are detailed in Note 14. The Company issued USD 2 billion of Senior Notes in June 2021 consisting of USD 1 billion 2.0% Senior Notes due in 2026 at a price equal to 99.827 percent and USD 1 billion 3.1% Senior Notes due in 2031 at a price equal to 99.81 percent with interest payable semi-annually. Capitalised financing fees relating to the bonds issuance amounted to MUSD 16.7 and are being amortised over the expected life of the bonds.

Financial liabilities amounted to MUSD 1,231.6 and are detailed in Note 15. Bank loans amounted to MUSD 1,200.0 and related to the outstanding term loans under the corporate credit facility. The Company repaid USD 2 billion of the corporate credit facility term loans in June 2021 following the bonds issuance and repaid a further USD 0.3 billion in November. Capitalised financing fees relating to the establishment of the credit facility amounted to MUSD 2.4 and are being amortised over the expected life of the facility. The lease commitments amounted to MUSD 34.0 and related to the lease commitments under IFRS 16.

Provisions amounted to MUSD 664.7 and are detailed in Note 16. The provision for site restoration amounted to MUSD 650.8 and related to the future decommissioning obligations. The provision for Lundin Energy's Unit Bonus Plan amounted to MUSD 10.3.

Deferred tax liabilities amounted to MUSD 3,120.6. 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.

Trade and other payables amounted to MUSD 404.2 and are detailed in Note 17. Trade payables amounted to MUSD 80.4. Overlift amounted to MUSD 27.0 and was attributable to an overlift position on the producing fields, mainly relating to oil from the Solveig field. Joint operations creditors and accrued expenses amounted to MUSD 209.0 and related to activity in Norway. Other accrued expenses amounted to MUSD 63.7 and other current liabilities amounted to MUSD 24.1.

Derivative instruments amounted to MUSD 90.7 and related to the marked-to-market valuation of outstanding interest rate and currency hedge contracts.

Current tax liabilities amounted to MUSD 1,573.7 and related to Norway. The current tax liabilities have increased during the year mainly due to a current tax charge for the year of MUSD 2,562.8 offset by cash tax payments of MUSD 1,387.3 during the year.

Payables to continuing operations amounted to MUSD 128.6 and equals the dividend liability as approved by the AGM held on 30 March 2021 in Stockholm which is paid in quarterly installments. The discontinued operations have committed to fund the dividend and this payable was settled early 2022 when the fourth quarterly dividend was paid to the shareholders.

Statement of Cash Flows

Changes in working capital

Changes in working capital for the year, as included in the consolidated statement of cash flows, amounted to MUSD -229.2 (MUSD 61.4). Working capital increases mainly related to higher receivables at the end of the year as a result of increasing oil and gas prices, partly offset by higher payables.

Parent Company

The business of the Parent Company is investment in and management of oil and gas assets and renewable energy projects. The net result for the Parent Company for the year amounted to MSEK 12,956.5 (MSEK 2,641.9). The net result for the year included MSEK 13,310.2 (MSEK 2,867.8) financial income as a result of received dividends from a subsidiary. The net result excluding received dividends amounted to MSEK -353.7 (MSEK -225.9).

The net result for the year included general and administrative expenses of MSEK 240.7 (MSEK 240.1) and net finance costs of MSEK 133.4 (MSEK 5.3) when excluding the received dividends as mentioned above.

Related Party Transactions

Lundin Energy recognises the following related parties: associated companies, jointly controlled entities, key management personnel and members of their close family or other parties that are partly, directly or indirectly controlled by key management personnel or of its family or of any individual that controls, or has joint control or significant influence over the entity.

During the second quarter, the Group entered into a sponsorship agreement with Team Tilt SA, a Swiss sailing racing team, for their participation in the SailGP high-speed racing catamaran series. The sponsorship agreement spans over three years, with an annual payment of between MUSD 2.6 to MUSD 3.5, with the first payment made in the fourth quarter of 2021.

Team Tilt SA's majority owner is Sebastien Schneiter, an internationally recognised sailor who has represented Switzerland at European, World and Olympic events. Sebastien Schneiter is a close family member of the Company's current Board member and former CEO Alex Schneiter.

Liquidity

In June 2021, Lundin Energy issued USD 2 billion of Senior Notes consisting of USD 1 billion 2.0% Senior Notes due in 2026 at a price equal to 99.827 percent and USD 1 billion 3.1% Senior Notes due in 2031 at a price equal to 99.81 percent. Interest will be payable semiannually and none of the bonds have financial covenants. The Company used the net proceeds, in combination with cash on hand, to repay USD 2.0 billion of the corporate credit facility term loans entered into in December 2020. On 15 July 2021, the Senior Notes were listed on the Securities Official List of the Luxembourg Stock Exchange.

In December 2020, Lundin Energy entered into a five year corporate credit facility of USD 5 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 with USD 2.0 billion term loans being repaid in June 2021 and USD 0.3 billion term loans being repaid in November 2021 leaving USD 1.2 billion term loans, split across three, four and five year maturities. 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 2023 carbon neutrality target. The Company achieved a lower interest rate margin over LIBOR during the year based on the ESG KPIs incorporated in the margin structure. The structure of the Facility is such, that it is compatible with the issued unsecured bonds through the debt capital markets at pari passu terms.

Once the transaction with Aker BP is completed, the renewable business, which is reported as continuing operations, will be debt free and have a cash balance of MUSD 130, to cover capital expenditure and other working capital items. The renewable business is expected to be free cash flow positive from late 2023, when the renewable portfolio has been fully built out and all projects are operational.

The Company currently has Baa3, BBB- and BBB- credit ratings from Moody's, S&P and Fitch respectively, all with a stable outlook.

Contingent liabilities

In November 2021 the Swedish Prosecution Authority brought criminal charges against Chairman of the Board Ian H. Lundin and Director Alex Schneiter in relation to past operations in Sudan from 1999 to 2003. The charges also include claims against the Company for a corporate fine of SEK 3,000,000 and forfeiture of economic benefits of SEK 1,391,791,000, which according to the Swedish Prosecution Authority represents the value of the gain of SEK 720,098,000 that the Company made on the sale of the business in 2003. Any corporate fine or forfeiture of economic benefits would only be imposed after an adverse conclusion of a trial. The Company refutes that there are any grounds for allegations of wrongdoing by any of its representatives and sees no circumstance in which a corporate fine or forfeiture could become payable. The Company considers this to be a contingent liability and therefore no provisions has been recognised. This contingent liability will remain with the continuing operations.

Subsequent Events

There are no subsequent events to report.

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 and during 2021, Lundin Energy used 216,708 of the purchased own shares for settlement of the 2018 performance based incentive plan resulting in 1,356,435 of its own shares held by the Company by the end of the year.

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

The first dividend payment was made on 8 April 2021, the second dividend payment was made on 7 July 2021, the third dividend payment was made on 7 October 2021 and the fourth dividend payment was made on 11 January 2022.

2021 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 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.

Ordinary cash dividend

As communicated by the Company on 29 October 2021 and in accordance with the dividend policy, the Board of Directors will propose to the 2022 Annual General Meeting a quarterly dividend of USD 0.5625 per share, corresponding to USD 160 million (rounded off) per quarter, which reflects a 25 percent increase compared to the 2020 dividend. Before payment, each quarterly dividend of USD 0.5625 per share will 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) prior to each record date. 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 prior to each record date.

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 dividend has been set to a cap of SEK 7.040 billion. If the total dividend would exceed the cap of SEK 7.040 billion, the dividend will be automatically adjusted downwards so that the dividend corresponds to the cap of SEK 7.040 billion.

On 21 December 2021, the Company entered into an agreement regarding a combination of Aker BP and the Company's E&P business. Completion of the combination with Aker BP is subject to certain terms and conditions, including approval by the Annual General Meeting of the Company and Aker BP receiving necessary governmental clearances. The Board of Directors will propose to the Annual General Meeting that quarterly dividends as per the above shall only be payable for as long as the Company owns the E&P business. Accordingly, no quarterly dividends shall be paid by the Company after the completion of the combination with Aker BP. According to a preliminary timetable, completion of the combination is planned to occur in late Q2 or early Q3 2022.

The Board of Directors' complete dividend proposal, including a proposed payment schedule and complete terms and conditions will be announced in connection with the notice of the Annual General Meeting.

Lex Asea distribution of the E&P business

The combination with Aker BP will be carried out as a statutory cross-border merger in accordance with Norwegian and Swedish law, through which Aker BP will absorb a company ("LEAB MergerCo") that will contain Lundin Energy's E&P business. Shortly before the completion of the combination with Aker BP, the shares in LEAB MergerCo will be distributed to the shareholders of Lundin Energy through a so-called lex asea dividend. The merger consideration that thereafter will be payable to the (new) shareholders of LEAB MergerCo will consist of a mix of cash and shares in Aker BP.

The Board of Directors' intends to propose to the 2022 Annual General Meeting that all shares in LEAB MergerCo are distributed to the shareholders, whereby one share in the Company shall entitle to one share in LEAB MergerCo.

The Board of Directors' lex asea dividend proposal, including complete terms and conditions will be announced in connection with the notice of the Annual General Meeting.

Remuneration

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

Unit Bonus Plan

The number of units relating to the awards made in 2019, 2020 and 2021 under the Unit Bonus Plan outstanding as at 31 December 2021 were 59,453, 171,530 and 219,969 respectively.

Performance Based Incentive Plan

The AGM 2021 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 2021 and the 2021 award is accounted for from the second half of 2021. The total outstanding number of awards at 31 December 2021 was 254,789 and the awards vest over three years from 1 July 2021 subject to certain performance conditions being met. The outstanding number of awards has increased from the original number of awards reflecting dividends paid since the award date. Each original award was fair valued at the date of grant at SEK 173.10 using an option pricing model.

The 2020 plan is effective from 1 July 2020 and the total outstanding number of awards at 31 December 2021 was 414,164 and the awards vest over three years from 1 July 2020 subject to certain performance conditions being met. The outstanding number of awards has increased from the original number of awards reflecting dividends paid since the award date. Each original award was fair valued at the date of grant at SEK 147.10 using an option pricing model.

The 2019 plan is effective from 1 July 2019 and the total outstanding number of awards at 31 December 2021 was 341,001 and the awards vest over three years from 1 July 2019 subject to certain performance conditions being met. The outstanding number of awards has increased from the original number of awards reflecting dividends paid since the award date. Each original award was fair valued at the date of grant at SEK 169.00 using an option pricing model.

Accounting Policies

The interim Group report has been prepared in accordance with International Accounting Standard (IAS) 34, Interim Financial Reporting.

The accounting policies adopted are in all aspects consistent with those followed in the preparation of the Group's annual financial statements for the year ended 31 December 2020. No accounting policy on IFRS5 was included in the Group's annual financial statements for the year ended 31 December 2020 and the following accounting policy has been applied in this interim Group report.

Non-current assets held for sale or distribution and discontinued operations

The Group classifies non-current assets and disposal groups as held for sale or distribution if their carrying amounts will be recovered principally through a sale transaction or distribution rather than through continuing use. Non-current assets and disposal groups classified as held for sale or distribution are measured at the lower of their carrying amount and fair value less costs to sell. Costs to sell are the incremental costs directly attributable to the disposal of an asset (disposal group), excluding finance costs and income tax expense.

The criteria for held for sale or distribution classification is regarded as met only when the sale or distribution is highly probable, and the asset or disposal group is available for immediate sale or distribution in its present condition. Actions required to complete the sale or distribution should indicate that it is unlikely that significant changes to the sale or distribution will be made or that the decision to sell or distribute will be withdrawn. Management must be committed to the plan to sell or distribute the asset and the sale or distribution expected to be completed within one year from the date of the classification.

Oil and gas properties, other tangible fixed assets and intangible assets are not depleted, depreciated or amortised anymore once classified as held for sale or distribution. Assets and liabilities classified as held for sale or distribution are presented separately as current items in the statement of financial position. Discontinued operations are excluded from the results of continuing operations and are presented as a single amount as profit or loss after tax from discontinued operations in the statement of profit or loss.

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

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

Risks and Risk Management

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

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

Ongoing COVID-19 Crisis

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

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 2021, Lundin Energy had outstanding foreign currency contracts as summarised below:

Buy	Sell	Average contractual Exchange rate	Settlement period
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

Buy	Sell	Average contractual strike price put options	Settlement period
MNOK 9,466.0	MUSD 1,143.6	NOK 8.28:USD 1	Jan 2022 –May 2022

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

Borrowings expressed in MUSD	Fixing of floating LIBOR average rate per annum	Settlement period
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, changes to the fair value of effective hedges are reflected in other comprehensive income and changes to the fair value of ineffective hedges are reflected directly in the income statement.

Exchange Rates

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

	31 Dec 2021		31 Dec 2020
	Average	Period end	Average	Period end
1 USD equals NOK	8.5904	8.8194	9.4146	8.5326
1 USD equals Euro	0.8450	0.8829	0.8762	0.8149
1 USD equals SEK	8.5765	9.0502	9.2092	8.1772
	Fourth quarter 2021		Fourth quarter 2020
	Average		Average
1 USD equals NOK		8.7205 9.0231
1 USD equals Euro	0.8741		0.8384
1 USD equals SEK	8.8523		8.6105

Consolidated Income Statement

Expressed in MUSD	Note	1 Jan 2021- 31 Dec 2021	1 Oct 2021- 31 Dec 2021	1 Jan 2020- 31 Dec 2020	1 Oct 2020- 31 Dec 2020
General, administration and depreciation expenses		12 months -19.4	3 months -3.6	12 months -16.4	3 months -3.7
Operating profit		-19.4	-3.6	-16.4	-3.7
Net financial items
Finance income	1	2.6	2.2	0.5	0.2
Finance costs	2	-0.2	–	-0.9	-0.2
		2.4	2.2	-0.4	0.0
Share in result of joint ventures		0.9	0.1	-0.1	-0.1
Loss before tax		-16.1	-1.3	-16.9	-3.8
Income tax		–	–	-1.0	-0.9
Net result from continuing operations		-16.1	-1.3	-17.9	-4.7
Discontinued operations
Net result - E&P business	3	509.9	123.0	402.1	308.4
		493.8	121.7	384.2	303.7
Attributable to:
Shareholders of the Parent Company		493.8	121.7	384.2	303.7
Earnings per share – USD
From continuing operations		-0.06	-0.00	-0.06	-0.02
From discontinued operations		1.80	0.43	1.41	1.09
		1.74	0.43	1.35	1.07
Earnings per share fully diluted – USD
From continuing operations		-0.06	-0.00	-0.06	-0.02
From discontinued operations		1.79	0.43	1.41	1.09
		1.73	0.43	1.35	1.07

Consolidated Statement of Comprehensive Income

Expressed in MUSD	1 Jan 2021- 31 Dec 2021 12 months	1 Oct 2021- 31 Dec 2021 3 months	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months
Net result	493.8	121.7	384.2	303.7
Items that may be subsequently reclassified to profit or loss:
Exchange differences foreign operations	181.2	64.1	-210.1	-63.7
Cash flow hedges	183.5	85.0	-63.4	115.1
Other comprehensive income, net of tax	858.5	270.8	-273.5	51.4
Total comprehensive income	858.5	270.8	110.7	355.1
Attributable to:
Shareholders of the Parent Company	858.5	270.8	110.7	355.1

Consolidated Balance Sheet

Expressed in MUSD	Note	31 December 2021	31 December 2020
ASSETS
Non-current assets
Oil and gas properties		–	5,902.4
Renewable energy properties		31.5	–
Other tangible fixed assets		0.1	45.2
Goodwill		–	128.1
Investments in joint ventures		108.7	110.6
Receivables from joint ventures		35.1	–
Financial assets		–	13.5
Trade and other receivables		–	17.3
Derivative instruments		–	3.8
Total non-current assets		175.4	6,220.9
Current assets
Assets held for distribution	3	7,468.2	–
Inventories		–	59.1
Trade and other receivables		5.3	278.6
Derivative instruments		–	12.1
Receivable from discontinued operations		128.6	–
Cash and cash equivalents		130.0	82.5
Total current assets		7,732.1	432.3
TOTAL ASSETS		7,907.5	6,653.2
EQUITY AND LIABILITIES
Equity
Shareholders´ equity		-1,419.3	-1,769.1
Liabilities
Non-current liabilities
Financial liabilities		–	3,983.9
Provisions		–	565.6
Deferred tax liabilities		–	2,893.9
Derivative instruments		–	144.7
Total non-current liabilities		–	7,588.1
Current liabilities
Liabilities held for distribution	3	9,194.0	–
Financial liabilities		–	6.1
Dividends		128.6	72.3
Trade and other payables		4.2	202.5
Derivative instruments		–	87.6
Current tax liabilities		–	444.4
Provisions		–	21.3
Total current liabilities		9,326.8	834.2
Total liabilities		9,326.8	8,422.3
TOTAL EQUITY AND LIABILITIES		7,907.5	6,653.2

Consolidated Statement of Cash Flows

Expressed in MUSD	1 Jan 2021- 31 Dec 2021 12 months	1 Oct 2021- 31 Dec 2021 3 months	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months
Cash flows from operating activities
Net result from continuing operations	-16.1	-1.3	-17.9	-4.7
Net result from discontinued operations	509.9	123.0	402.1	308.4
Adjustments for:
Exploration costs	258.1	20.2	104.9	57.6
Depletion, depreciation and amortisation	703.2	166.7	614.6	162.6
Current tax	2,562.8	880.1	511.8	260.6
Deferred tax	329.7	82.6	378.3	34.6
Long-term incentive plans	6.1	3.8	9.5	4.1
Foreign currency exchange gain/ loss	186.4	58.2	-230.3	-260.6
Interest expense	52.0	17.0	104.3	26.4
Unwinding of loan modification gain	–	–	99.7	70.6
Amortisation of deferred financing fees	35.5	18.2	37.6	25.3
Ineffective hedging contracts	68.9	41.7	–	–
Other	38.2	10.8	6.3	-6.5
Interest received	1.2	0.4	0.8	0.2
Interest paid	-50.9	-10.1	-126.6	-33.3
Income taxes paid / received	-1,397.8	-710.2	-428.5	-337.6
Changes in working capital	-229.2	-143.0	61.4	-31.0
Total cash flows from operating activities	3,058.0	558.1	1,528.0	276.7
- of which relates to continuing operations	-17.7	-5.2	-18.1	-4.7
- of which relates to discontinued operations	3,075.7	563.3	1,546.1	281.4
Cash flows from investing activities
Investment in oil and gas properties	-1,319.5	-529.3	-919.7	-340.5
Investment in renewable energy business1	-77.3	-2.4	-99.8	-19.0
Investment in other fixed assets	-4.1	-3.1	-2.4	-0.8
Decommissioning costs paid	-11.6	-0.7	-57.9	-13.9
Total cash flows from investing activities	-1,412.5	-535.5	-1,079.8	-374.2
- of which relates to continuing operations	-71.7	-0.6	-99.8	-19.0
- of which relates to discontinued operations	-1,340.8	-534.9	-980.0	-355.2
Cash flows from financing activities
Senior Notes	1,996.4	–	–	–
Net drawdown/repayment of corporate credit facility	-2,794.0	-300.0	3,994.0	3,994.0
Net drawdown/repayment of reserve-based lending facility	–	–	-4,092.0	-3,836.0
Repayment of principal portion of lease commitments	-26.6	-9.2	-3.2	-0.8
Financing fees paid	-21.3	–	-36.8	-34.3
Dividends paid	-455.0	-128.0	-318.2	-71.1
Total cash flows from financing activities	-1,300.5	-437.2	-456.2	51.8
- of which relates to continuing operations	-455.0	-128.0	-318.2	-71.1
- of which relates to discontinued operations	-845.5	-309.2	-138.0	122.9
Change in cash and cash equivalents	345.0	-414.6	-8.0	-45.7
Cash and cash equivalents at the beginning of the period	82.5	853.1	85.3	129.2
Currency exchange difference in cash and cash equivalents	24.6	13.6	5.2	-1.0
Cash and cash equivalents at the end of the period	452.1	452.1	82.5	82.5
- of which is included in assets held for distribution continuing	322.1	322.1	–	–
- of which excludes assets held for distribution	130.0	130.0	82.5	82.5

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

Consolidated Statement of Changes in Equity

Expressed in MUSD	Share capital	Additional paid-in capital / Other reserves	Retained earnings	Dividends	Total equity
At 1 January 2020	0.5	-169.7	-1,429.6	–	-1,598.8
Comprehensive income
Net result	–	–	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
Transfer of prior year dividends	–	–	-284.1	284.1	–
Comprehensive income
Net result	–	–	493.8	–	493.8
Other comprehensive income	–	364.7	–	–	364.7
Total comprehensive income	–	364.7	493.8	–	858.5
Transactions with owners
Distributions	–	–	–	-511.8	-511.8
Issuance of treasury shares	–	6.4	–	–	6.4
Share based payments	–	-9.0	–	–	-9.0
Value of employee services	–	–	5.7	–	5.7
Total transaction with owners	–	-2.6	5.7	-511.8	-508.7
At 31 December 2021	0.5	-83.4	-824.6	-511.8	-1,419.3

Note 1 – Finance income - continuing operations MUSD	1 Jan 2021- 31 Dec 2021 12 months	1 Oct 2021- 31 Dec 2021 3 months	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months
Foreign currency exchange gain, net	0.2	0.1	–	–
Interest income	1.0	0.7	0.5	0.2
Other	1.4	1.4	–	–
Finance income	2.6	2.2	0.5	0.2

Note 2 – Finance costs - continuing operations MUSD	1 Jan 2021- 31 Dec 2021 12 months	1 Oct 2021- 31 Dec 2021 3 months	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months
Foreign currency exchange loss, net	–	–	0.8	0.2
Other	0.2	–	0.1	0.0
Finance costs	0.2	–	0.9	0.2

Note 3 – Discontinued operations - E&P business

On 21 December 2021, Lundin Energy announced that it had entered into an agreement with Aker BP whereby Aker BP will absorb Lundin Energy's E&P business through a cross-border merger in accordance with Norwegian and Swedish law. Before completion of the cross-border merger, the shares in the company holding Lundin Energy's E&P business will be distributed to Lundin Energy shareholders. The results of the E&P business are included in Lundin Energy's financial statements in the reporting period and are shown as discontinued operations. The assets and liabilities associated with the E&P business are presented as assets and liabilities held for distribution in the consolidated balance sheet.

The financial performance of the discontinued operations and net assets held for distribution is as follows:

	Note	1 Jan 2021- 31 Dec 2021	1 Oct 2021- 31 Dec 2021	1 Jan 2020- 31 Dec 2020	1 Oct 2020- 31 Dec 2020
Expressed in MUSD		12 months	3 months	12 months	3 months
Revenue and other income	4
Revenue		5,452.9	1,615.8	2,533.2	773.4
Other income		31.8	6.0	31.2	6.3
		5,484.7	1,621.8	2,564.4	779.7
Cost of sales
Production costs	5	-265.4	-78.0	-177.2	-38.0
Depletion and decommissioning costs		-703.0	-171.8	-607.7	-160.9
Exploration costs		-258.1	-20.2	-104.9	-57.6
Purchase of crude oil from third parties		-361.7	-72.5	-217.8	-24.5
Gross profit	6	3,896.5	1,279.3	1,456.8	498.7
General, administration and depreciation expenses		-22.5	-7.3	-19.7	-6.9
Operating profit		3,874.0	1,272.0	1,437.1	491.8
Net financial items
Finance income	7	1.2	0.4	172.6	171.9
Finance costs	8	-472.8	-186.7	-318.5	-61.0
		-471.6	-186.3	-145.9	110.9
Profit before tax		3,402.4	1,085.7	1,291.2	602.7
Income tax	9	-2,892.5	-962.7	-889.1	-294.3
Net result from discontinued operations		509.9	123.0	402.1	308.4

Expressed in MUSD	Note	31 December 2021	31 December 2020
Assets held for distribution
Oil and gas properties	10	6,222.2	–
Other tangible fixed assets	11	42.0	–
Goodwill		128.1	–
Financial assets	12	12.7	–
Inventories		55.7	–
Trade and other receivables	13	657.2	–
Derivative instruments	18	18.5	–
Current tax assets		9.7	–
Cash and cash equivalents		322.1	–
Total assets held for distribution		7,468.2	–
Liabilities held for distribution
Bonds	14	1,979.9	–
Financial liabilities	15	1,231.6	–
Provisions	16	664.7	–
Deferred tax liabilities		3,120.6	–
Trade and other payables	17	404.2	–
Derivative instruments	18	90.7	–
Current tax liabilities		1,573.7	–
Payable to continuing operations		128.6	–
Total liabilities held for distribution		9,194.0	–
Net assets held for distribution		-1,725.8	–
Amounts included in accumulated other comprehensive income:
Foreign currency translation reserve		-397.6	–
Hedging reserves		-18.8	–
Reserves of disposal Group classified as held for distribution		-416.4	–

Note 4 – Revenue and other income - discontinued operations - MUSD	1 Jan 2021- 31 Dec 2021 12 months	1 Oct 2021- 31 Dec 2021 3 months	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months
Revenue
Crude oil from own production	4,535.1	1,273.0	2,168.5	690.5
Crude oil from third party activities	364.4	72.8	221.5	24.9
Condensate	113.5	44.3	63.8	23.6
Gas	439.9	225.7	79.4	34.4
Sales of oil and gas	5,452.9	1,615.8	2,533.2	773.4
Other income	31,8	6.0	31.2	6.3
Revenue and other income	5,484.7	1,621.8	2,564.4	779.7

Note 5 – Production costs - discontinued operations MUSD	1 Jan 2021- 31 Dec 2021 12 months	1 Oct 2021- 31 Dec 2021 3 months	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months
Cost of operations	167.5	51.5	134.5	32.6
Tariff and transportation expenses	71.9	20.9	50.7	14.3
Change in under/over lift position	7.9	3.6	-2.7	1.2
Change in inventory position	11.6	0.4	-11.2	-11.6
Other	6.5	1.6	5.9	1.5
Production costs	265.4	78.0	177.2	38.0

Note 6 – Segment information - discontinued operations MUSD	1 Jan 2021- 31 Dec 2021 12 months	1 Oct 2021- 31 Dec 2021 3 months	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months
Norway
Crude oil from own production	4,535.1	1,273.0	2,168.5	690.5
Condensate	113.5	44.3	63.8	23.6
Gas	439.9	225.7	79.4	34.4
Revenue	5,088.5	1,543.0	2,311.7	748.5
Other income	31.8	6.0	30.3	6.3
Revenue and other income	5,120.3	1,549.0	2,342.0	754.8
Production costs	-265.4	-78.0	-177.2	-38.0
Depletion and decommissioning costs	-703.0	-171.8	-607.7	-160.9
Exploration costs	-258.1	-20.2	-104.9	-57.6
Gross profit	3,893.8	1,279.0	1,452.2	498.3
Other
Crude oil from third party activities	364.4	72.8	221.5	24.9
Revenue	364.4	72.8	221.5	24.9
Other income	–	–	0.9	–
Revenue and other income	364.4	72.8	222.4	24.9
Purchase of crude oil from third parties	-361.7	-72.5	-217.8	-24.5
Gross profit	2.7	0.3	4.6	0.4
Total
Crude oil from own production	4,535.1	1,273.0	2,168.5	690.5
Crude oil from third party activities	364.4	72.8	221.5	24.9
Condensate	113.5	44.3	63.8	23.6
Gas	439.9	225.7	79.4	34.4
Revenue	5,452.9	1,615.8	2,533.2	773.4
Other income	31.8	6.0	31.2	6.3
Revenue and other income	5,484.7	1,621.8	2,564.4	779.7
Production costs	-265.4	-78.0	-177.2	-38.0
Depletion and decommissioning costs	-703.0	-171.8	-607.7	-160.9
Exploration costs	-258.1	-20.2	-104.9	-57.6
Purchase of crude oil from third parties	-361.7	-72.5	-217.8	-24.5
Gross profit	3,896.5	1,279.3	1,456.8	498.7

Note 7 – Finance income - discontinued operations MUSD	1 Jan 2021- 31 Dec 2021 12 months	1 Oct 2021- 31 Dec 2021 3 months	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months
Foreign currency exchange gain, net	–	–	171.8	171.8
Interest income	1.2	0.4	0.8	0.1
Finance income	1.2	0.4	172.6	171.9

Note 8 – Finance costs - discontinued operations MUSD	1 Jan 2021- 31 Dec 2021 12 months	1 Oct 2021- 31 Dec 2021 3 months	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months
Foreign currency exchange loss, net	216.3	83.8	–	-84.6
Interest expense	52.5	17.5	104.4	26.5
Loss on interest rate hedges	122.0	42.6	44.5	15.2
Unwinding of site restoration discount	20.8	5.4	19.2	5.1
Amortisation of deferred financing fees	35.5	18.2	37.6	25.3
Loan facility commitment fees	7.2	1.9	11.5	2.8
Unwinding of loan modification gain	–	–	99.7	70.6
Other	18.5	17.3	1.6	0.1
Finance costs	472.8	186.7	318.5	61.0

Note 9 – Income tax - discontinued operations MUSD	1 Jan 2021- 31 Dec 2021 12 months	1 Oct 2021- 31 Dec 2021 3 months	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months
Current tax	2,562.8	880.1	510.8	259.7
Deferred tax	329.7	82.6	378.3	34.6
Income tax	2,892.5	962.7	889.1	294.3

Note 10 – Oil and gas properties - assets held for distribution MUSD	31 December 2021	31 December 2020
Producing assets	4,415.3	–
Assets under development	794.4	–
Capitalised exploration and appraisal expenditure	1,007.2	–
Right of use assets	5.3	–
	6,222.2	–

Note 11 – Other tangible fixed assets - assets held for distribution MUSD	31 December 2021	31 December 2020
Right of use assets	27.2	–
Other	14.8	–
	42.0	–

Note 12 – Financial assets - assets held for distribution MUSD	31 December 2021	31 December 2020
Contingent consideration	12.4	–
Associated companies	0.3	–
	12.7	–

Note 13 – Trade and other receivables - assets held for distribution MUSD	31 December 2021	31 December 2020
Trade receivables	523.9	–
Underlift	23.2	–
Joint operations debtors	36.2	–
Prepaid expenses and accrued income	68.7	–
Other	5.2	–
	657.2	–

Note 14 – Bonds - liabilities held for distribution MUSD	31 December 2021	31 December 2020
Senior Notes 2.0% (21/26) - maturity July 2026	1,000.0	–
Senior Notes 3.1% (21/31) - maturity July 2031	1,000.0	–
Discount on bonds issuance	-3.4	–
Capitalised financing fees	-16.7	–
	1,979.9	–

Note 15 – Financial liabilities - liabilities held for distribution MUSD	31 December 2021	31 December 2020
Bank loans	1,200.0	–
Capitalised financing fees	-2.4	–
Lease commitments	34.0	–
	1,231.6	–

Note 16 – Provisions - liabilities held for distribution MUSD	31 December 2021	31 December 2020
Site restoration	650.8	–
Long-term incentive plans	10.3	–
Other	3.6	–
	664.7	–

Note 17 – Trade and other payables - liabilities held for distribution MUSD	31 December 2021	31 December 2020
Trade payables	80.4	–
Overlift	27.0	–
Joint operations creditors and accrued expenses	209.0	–
Other accrued expenses	63.7	–
Other	24.1	–
	404.2	–

Note 18 – Financial Instruments - liabilities held for distribution

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 2021 MUSD	Level 1	Level 2	Level 3
Assets held for distribution
Contingent consideration	–	–	12.4
Derivative instruments	–	18.5	–
	–	18.5	12.4
Liabilities held for distribution
Derivative instruments	–	90.7	–
	–	90.7	–

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 material changes in subsequent years.

Note 19 – Additional disclosures

Additional disclosures supplementing the financial statements are included in the Financial Review section of this report on pages 8-16.

Parent Company Income Statement

	1 Jan 2021- 31 Dec 2021	1 Oct 2021- 31 Dec 2021	1 Jan 2020- 31 Dec 2020	1 Oct 2020- 31 Dec 2020
Expressed in MSEK	12 months	3 months	12 months	3 months
Revenue	20.4	9.8	19.5	7.2
General and administration expenses	-240.7	-59.1	-240.1	-64.4
Operating loss	-220.3	-49.3	-220.6	-57.2
Net financial items
Finance income	13,310.2	8,843.0	2,867.8	–
Finance costs	-133.4	-133.1	-5.3	-1.2
	13,176.8	8,709.9	2,862.5	-1.2
Profit before tax	12,956.5	8,660.6	2,641.9	-58.4
Income tax	–	–	–	–
Net result	12,956.5	8,660.6	2,641.9	-58.4

Parent Company Comprehensive Income Statement

Expressed in MSEK	1 Jan 2021- 31 Dec 2021 12 months	1 Oct 2021- 31 Dec 2021 3 months	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months
Net result	12,956.5	8,660.6	2,641.9	-58.4
Other comprehensive income	–	–	–	–
Total comprehensive income	12,956.5	8,660.6	2,641.9	-58.4
Attributable to:
Shareholders of the Parent Company	12,956.5	8,660.6	2,641.9	-58.4
	12,956.5	8,660.6	2,641.9	-58.4

Parent Company Balance Sheet

Expressed in MSEK	31 December 2021	31 December 2020
ASSETS
Non-current assets
Shares in subsidiaries	55,118.9	55,118.9
Other tangible fixed assets	0.4	0.5
Total non-current assets	55,119.3	55,119.4
Current assets:
Receivables	9,813.9	568.5
Cash and cash equivalents	44.3	26.6
Total current assets	9,858.2	595.1
TOTAL ASSETS	64,977.5	55,714.5
SHAREHOLDERS´EQUITY AND LIABILITIES
Shareholders´ equity including net result for the period	63,625.5	55,080.0
Non-current liabilities
Provisions	1.6	0.9
Total non-current liabilities	1.6	0.9
Current liabilities
Dividends	1,163.9	591.5
Other liabilities	186.5	42.1
Total current liabilities	1,350.4	633.6
Total liabilities	1,352.0	634.5
TOTAL EQUITY AND LIABILITIES	64,977.5	55,714.5

Parent Company Cash Flow Statement

	1 Jan 2021-	1 Oct 2021-	1 Jan 2020-	1 Oct 2020-
Expressed in MSEK	31 Dec 2021 12 months	31 Dec 2021 3 months	31 Dec 2020 12 months	31 Dec 2020 3 months
Cash flow from operations
Net result	12,956.5	8,660.6	2,641.9	-58.4
Adjustment for non-cash related items	-9,772.0	-7,540.2	-711.0	718.6
Changes in working capital	674.0	2.9	1,007.3	-15.5
Total cash flow from operations	3,858.5	1,123.3	2,938.2	644.7
Cash flow from investing
Investments in other fixed assets	-0.1	-0.1	-0.2	–
Total cash flow from investing	-0.1	-0.1	-0.2	–
Cash flow from financing
Dividends paid	-3,898.5	-1,117.5	-3,003.1	-648.3
Issuance of treasury shares	56.2	–	63.1	–
Total cash flow from financing	-3,842.3	-1,117.5	-2,940.0	-648.3
Change in cash and cash equivalents	16.1	5.7	-2.0	-3.6
Cash and cash equivalents at the beginning of the period	26.6	38.0	31.7	32.1
Currency exchange difference in cash and cash equivalents	1.6	0.6	-3.1	-1.9
Cash and cash equivalents at the end of the period	44.3	44.3	26.6	26.6

Parent Company Statement of Changes in Equity

		Restricted equity	Unrestricted equity
	Share	Statutory	Other	Retained			Total
Expressed in MSEK	capital	reserve	reserves	earnings	Dividends	Total	equity
Balance at 1 January 2020	3.5	861.3	6,479.7	47,898.3	–	54,378.0	55,242.8
Total comprehensive income	–	–	–	2,641.9	–	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
Transfer of prior year dividends	–	–	–	-2,867.8	2,867.8	–	–
Total comprehensive income	–	–	–	12,956.5	–	12,956.5	12,956.5
Transactions with owners
Distributions	–	–	–	–	-4,467.2	-4,467.2	-4,467.2
Issuance of treasury shares	–	–	56.2	–	–	56.2	56.2
Total transactions with owners	–	–	56.2	–	-4,467.2	-4,411.0	-4,411.0
Balance at 31 December 2021	3.5	861.3	6,599.0	60,628.9	-4,467.2	62,760.7	63,625.5

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 pages. Definitions of the performance measures are provided under the key ratio definitions:

Financial data	1 Jan 2021- 31 Dec 2021	1 Oct 2021- 31 Dec 2021	1 Jan 2020- 31 Dec 2020	1 Oct 2020- 31 Dec 2020
MUSD	12 months	3 months	12 months	3 months
Revenue and other income
From continuing operations	–	–	–	–
From discontinuing operations	5,484.7	1,621.8	2,564.4	779.7
	5,484.7	1,621.8	2,564.4	779.7
Operating cash flow
From continuing operations	–	–	-1.0	-0.9
From discontinuing operations	2,294.8	591.2	1,658.6	457.5
	2,294.8	591.2	1,657.6	456.6
CFFO
From continuing operations	-17.7	-5.2	-18.1	-4.7
From discontinuing operations	3,075.7	563.3	1,546.1	281.4
	3,058.0	558.1	1,528.0	276.7
EBITDAX
From continuing operations	-19.4	-3.6	-16.4	-3.7
From discontinuing operations	4,842.2	1,465.8	2,156.6	712.1
	4,822.8	1,462.2	2,140.2	708.4
Free cash flow
From continuing operations	-89.4	-5.8	-117.9	-23.7
From discontinuing operations	1,734.9	28.4	566.1	-73.8
	1,645.5	22.6	448.2	-97.5
Net result
From continuing operations	-16.1	-1.3	-17.9	-4.7
From discontinuing operations	509.9	123.0	402.1	308.4
	493.8	121.7	384.2	303.7
Adjusted net result
From continuing operations	-16.3	-1.4	-17.1	-4.5
From discontinuing operations	812.0	254.7	297.1	91.4
	795.7	253.3	280.0	86.9
Net debt	2,747.9	2,747.9	3,911.5	3,911.5

Data per share USD	1 Jan 2021- 31 Dec 2021 12 months	1 Oct 2021- 31 Dec 2021 3 months	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months
Operating cash flow per share
From continuing operations	–	–	-0.00	-0.00
From discontinuing operations	8.07	2.08	5.83	1.61
	8.07	2.08	5.83	1.61
CFFO per share
From continuing operations	-0.06	-0.02	-0.06	-0.02
From discontinuing operations	10.81	1.98	5.44	0.99
	10.75	1.96	5.38	0.97
EBITDAX per share
From continuing operations	-0.07	-0.01	-0.06	-0.01
From discontinuing operations	17.03	5.15	7.59	2.50
	16.96	5.14	7.53	2.49
Free cash flow per share
From continuing operations	-0.31	-0.02	-0.42	-0.08
From discontinuing operations	6.10	0.10	2.00	-0.26
	5.79	0.08	1.58	-0.34
Earnings per share
From continuing operations	-0.06	-0.00	-0.06	-0.02
From discontinuing operations	1.80	0.43	1.41	1.09
	1.74	0.43	1.35	1.07
Earnings per share fully diluted
From continuing operations	-0.06	-0.00	-0.06	-0.02
From discontinuing operations	1.79	0.43	1.41	1.09
	1.73	0.43	1.35	1.07
Adjusted earnings per share
From continuing operations	-0.06	-0.00	-0.06	-0.02
From discontinuing operations	2.86	0.89	1.05	0.33
	2.80	0.89	0.99	0.31
Adjusted earnings per share fully diluted
From continuing operations	-0.06	-0.00	-0.06	-0.02
From discontinuing operations	2.85	0.89	1.04	0.32
	2.79	0.89	0.98	0.30
Shareholders' equity per share	-4.99	-4.99	-6.22	-6.22
Dividend per share1	1.60	0.45	1.12	0.25
Yield	4	1	4	1
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	284,568,178	284,568,178	284,351,471	284,351,471
Weighted average number of shares for the period	284,444,685	284,568,178	284,177,604	284,351,471
Weighted average number of shares for the period fully diluted	285,126,595	285,101,892	284,830,491	284,801,383

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

	1 Jan 2021- 31 Dec 2021	1 Oct 2021- 31 Dec 2021	1 Jan 2020- 31 Dec 2020	1 Oct 2020- 31 Dec 2020
Share price	12 months	3 months	12 months	3 months
Share price at period end in SEK	324.50	324.50	222.30	222.30
Share price at period end in USD1	35.86	35.86	27.19	27.19
Key ratios from continuing operations2
Return on equity (%)	-6	0	-10	-3
Return on capital employed (%)	-6	-1	-9	-2
Net debt/equity ratio (%)	–	–	–	–
Net debt/EBITDAX ratio	–	–	–	–
Equity ratio (%)	70	70	76	76
Share of risk capital (%)	70	70	76	76
Interest coverage ratio	–	–	–	–
Operating cash flow/interest ratio	–	–	–	–

1 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.

2 Key ratios from continuing operations are calculated based on equity attributable to the continuing operations only instead of equity as presented in the consolidated balance sheet and based on no debt attributable to the continuing operations.

Relevant Reconciliations of Alternative Performance Measures

EBITDAX MUSD	1 Jan 2021- 31 Dec 2021 12 months	1 Oct 2021- 31 Dec 2021 3 months	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months
From continuing operations
Operating profit	-19.4	-3.6	-16.4	-3.7
EBITDAX	-19.4	-3.6	-16.4	-3.7

EBITDAX MUSD	1 Jan 2021- 31 Dec 2021 12 months	1 Oct 2021- 31 Dec 2021 3 months	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months
From discontinuing operations
Operating profit	3,874.0	1,272.0	1,437.1	491.8
Add: depletion of oil and gas properties	703.0	171.8	607.7	160.9
Add: exploration costs	258.1	20.2	104.9	57.6
Add: depreciation of other tangible assets	7.1	1.8	6.9	1.8
EBITDAX	4,842.2	1,465.8	2,156.6	712.1

Operating cash flow MUSD	1 Jan 2021- 31 Dec 2021 12 months	1 Oct 2021- 31 Dec 2021 3 months	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months
From continuing operations
Revenue and other income	–	–	–	–
Minus: current taxes	–	–	-1.0	-0.9
Operating cash flow	–	–	-1.0	-0.9

Operating cash flow MUSD	1 Jan 2021- 31 Dec 2021 12 months	1 Oct 2021- 31 Dec 2021 3 months	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months
From discontinuing operations
Revenue and other income	5,484.7	1,621.8	2,564.4	779.7
Minus: production costs	-265.4	-78.0	-177.2	-38.0
Minus: purchase of crude oil from third parties	-361.7	-72.5	-217.8	-24.5
Minus: current taxes	-2,562.8	-880.1	-510.8	-259.7
Operating cash flow	2,294.8	591.2	1,658.6	457.5

Free cash flow MUSD	1 Jan 2021- 31 Dec 2021 12 months	1 Oct 2021- 31 Dec 2021 3 months	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months
From continuing operations
Cash flows from operating activities (CFFO)	-17.7	-5.2	-18.1	-4.7
Minus: cash flows from investing activities	-71.7	-0.6	-99.8	-19.0
Free cash flow	-89.4	-5.8	-117.9	-23.7

Free cash flow MUSD	1 Jan 2021- 31 Dec 2021 12 months	1 Oct 2021- 31 Dec 2021 3 months	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months
From discontinuing operations
Cash flows from operating activities (CFFO)	3,075.7	563.3	1,546.1	281.4
Minus: cash flows from investing activities	-1,340.8	-534.9	-980.0	-355.2
Free cash flow	1,734.9	28.4	566.1	-73.8

Adjusted net result MUSD	1 Jan 2021- 31 Dec 2021 12 months	1 Oct 2021- 31 Dec 2021 3 months	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months
From continuing operations
Net result	-16.1	-1.3	-17.9	-4.7
Adjusted for foreign currency exchange gain or loss	-0.2	-0.1	0.8	0.2
Adjusted net result	-16.3	-1.4	-17.1	-4.5

Adjusted net result MUSD	1 Jan 2021- 31 Dec 2021 12 months	1 Oct 2021- 31 Dec 2021 3 months	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months
From discontinuing operations
Net result	509.9	123.0	402.1	308.4
Adjusted for unwinding of loan modification gain	–	–	99.7	70.6
Adjusted for foreign currency exchange gain or loss	216.1	83.5	-171.8	-256.4
Adjusted for ineffective interest rate hedge contracts	71.0	35.7	–	–
Adjusted for other non recurring finance costs	15.4	15.4	–	–
Adjusted for tax effects of above mentioned items	-0.4	-2.9	-32.9	-31.2
Adjusted net result	812.0	254.7	297.1	91.4

Net debt MUSD	1 Jan 2021- 31 Dec 2021 12 months	1 Oct 2021- 31 Dec 2021 3 months	1 Jan 2020- 31 Dec 2020 12 months	1 Oct 2020- 31 Dec 2020 3 months
Senior Notes	2,000.0	2,000.0	–	–
Bank loans	1,200.0	1,200.0	3,994.0	3,994.0
Minus: cash and cash equivalents	-452.1	-452.1	-82.5	-82.5
Net debt	2,747.9	2.747.9	3,911.5	3,911.5

Key Ratio Definitions

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Net debt: Bonds plus bank loan less cash and cash equivalents.

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

Net debt/equity ratio: Bonds plus 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 2021 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, 1 February 2022

Ian H. Lundin Chairman

Nick Walker President and CEO Alex Schneiter Board Member

Peggy Bruzelius Board Member

C. Ashley Heppenstall Board Member

Lukas H. Lundin Board Member

Torstein Sanness Board Member

Grace Reksten Skaugen Board Member

Jakob Thomasen Board Member

Cecilia Vieweg Board Member Adam I. Lundin Board Member

Financial Information

The Company will publish the following reports:

• The three month report (January March 2022) will be published on 27 April 2022.
• The six month report (January June 2022) will be published on 27 July 2022.
• The nine month report (January September 2022) will be published on 26 October 2022.

The AGM will be held on 31 March 2022 in Stockholm, Sweden.

For further information, please contact:

Edward Westropp VP Investor Relations and Communications Tel: +41 22 595 10 14 edward.westropp@lundin-energy.com

Robert Eriksson Director of media and corporate affairs Tel: +46 701 11 26 15 robert.eriksson@lundin-energy.com

Definitions and abbreviations

CHF	Swiss franc
EUR	Euro
NOK	Norwegian Krone
SEK	Swedish Krona
USD	US dollar
TSEK	Thousand SEK
TUSD	Thousand USD
MEUR	Million EUR
MSEK	Million SEK
MUSD	Million USD
BUSD	Billion 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
CO2	Carbon dioxide
CO2 e	Carbon dioxide equivalents
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

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

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