Q Report for the NINE MONTHS ended 30 September 2020 3

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

Highlights

Strong free cash flow generation of MUSD 546 with an achieved oil price of USD 38.07 per boe for the first nine months.
Third quarter production of 157.5 Mboepd and free cash flow of MUSD 164
Full year production guidance increased from 157 Mboepd to 161 163 Mboepd and fourth quarter production targeting approximately 175 Mboepd
Edvard Grieg reserves increased by 50 MMboe to 350 MMboe gross 2P ultimate recovery and plateau production extended by a further year to late 2023
First nine months net carbon intensity for all assets of 2.7 kg CO2 per boe, below full year guidance of less than 4 kg CO2 per boe • Acquired portfolio of interests in the Barents Sea, including 10 percent working interest in high quality Wisting oil discovery and
further interest in the Alta discovery from Idemitsu Petroleum Norge AS (IPN) for USD 1.80 per boe
High impact exploration programme commenced in October 2020, targeting more than 350 MMboe net unrisked resources from four wells
Nick Walker, COO, appointed President and CEO and Daniel Fitzgerald appointed COO from 1 January 2021

Financial summary

	1 Jan 2020-	1 Jul 2020-	1 Jan 2019-	1 Jul 2019-	1 Jan 2019-
	30 Sep 2020	30 Sep 2020	30 Sep 2019	30 Sep 2019	31 Dec 2019
	9 months	3 months	9 months	3 months	12 months
Production in Mboepd	157.6	157.5	79.2	82.7	93.3
Revenue and other income in MUSD	1,784.7	687.0	2,199.0	1,215.0	2,948.7
CFFO in MUSD	1,251.3	353.2	985.3	230.8	1,378.2
Per share in USD	4.40	1.24	3.02	0.76	4.36

EBITDA in MUSD1	1,431.8	515.6	1,222.9	411.3	1,918.4
Per share in USD1	5.04	1.81	3.75	1.36	6.07

Free cash flow in MUSD	545.7	164.2	1,117.9	950.5	1,271.7
Per share in USD	1.92	0.58	3.42	2.91	4.03

Net result in MUSD	80.5	212.3	669.6	519.9	824.9
Per share in USD	0.28	0.74	2.05	1.72	2.61

Adjusted net result in MUSD	193.1	75.8	173.8	45.4	252.7
Per share in USD	0.68	0.27	0.53	0.15	0.80

Net debt in MUSD	3,706.8	3,706.8	4,054.9	4,054.9	4,006.7

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

Comment from Alex Schneiter, President and CEO of Lundin Energy:

"Following a volatile and unpredictable first half of 2020, the third quarter was one of financial and operational discipline and delivery, capitalising on our strict cost control and efficient production portfolio, driving free cashflow for the nine months period to MUSD 546 and further deleveraging of the Balance Sheet.

"Although production was curtailed from June 2020 due to the Norwegian Government restrictions, our portfolio of producing assets has the capacity to produce considerably more and we enjoyed strong facilities and reservoir performance across the portfolio during the reporting period. We are pleased to report that in the fourth quarter 2020, our fields have been granted increased production permits by the authorities, meaning we will now target approximately 175 Mboepd for the fourth quarter, raising our full year production guidance to a range of 161 to 163 Mboepd, from the previously guided target of 157 Mboepd.

"The Edvard Grieg field has exceeded expectations ever since it came on stream in 2015 and during the quarter we were able to reiterate its outperformance once again, with a significant reserves increase and a further extension of the plateau production. This really has been a Company making asset and I believe it will continue to surprise on the upside, especially when taking into account the extensive surrounding prospectivity, which will provide further organic growth opportunities well into the future. At Johan Sverdrup, performance has continued on or above expectations and we look forward to the results of the next Phase 1 oil capacity testing, which will occur during the fourth quarter of this year.

"I am also very pleased that we have restarted our 2020 exploration programme with the Polmak well in the Southern Barents Sea in October 2020. Polmak along with three other high impact wells are targeting net unrisked resources of over 350 MMboe and each, if successful, has the potential to add significant value and future growth to the business. To supplement our successful organic growth strategy, I have always maintained that we would look to do opportunistic and value accretive M&A deals and we were pleased to announce in October 2020, the acquisition of a portfolio of assets in the Barents Sea from IPN for USD 1.80 per boe, including the large Wisting discovery. This package further crystalizes our position in the Southern Barents Sea and gives us a great entry into one of the next large oil developments in Norway. Also, the Company continues to be very active in all its other core areas, through maturing its existing licences and evaluating new areas of interest for future growth.

"On the decarbonisation strategy, we continue to progress the electrification of our key producing assets which will see over 95 percent of our production fully electrified by the time the Edvard Grieg platform is powered from shore by the end of 2022. We are also continuing to develop and invest in renewable projects with the aim to offset and replace all our net electricity consumption as well as continuing to invest in innovative solutions to further improve our overall production efficiency. Our ultimate objective is to be one of the first E&P companies to reach carbon neutrality from our operations. I'm pleased to say that we are well on track to achieve just that.

Highlights

"On a personal note, I announced during the period, my intention to stand down as the President and CEO in January 2021 and hand over the reins to Nick Walker, the current COO. Nick is uniquely placed to lead this business into the next phase of growth. Having worked together for a number of years, I know that he shares the same passion and ambitions as I and the rest of the management team, to continue to be one of the most efficient, lowest cost and lowest emissions E&P businesses.

"I am standing down at a very exciting time for the Company; with its clear growth pathway, which is supported by one of the most efficient and lowest cost portfolios in the industry. One of my proudest achievements at Lundin Energy is being part of a business which I believe epitomizes how an E&P business can flourish and create value through the energy transition. The 'triple bottom line' of profitable growth, social progress and environmental benefit define this and when combined with the resilience of the Company to the oil price cycles, Lundin Energy is uniquely placed to continue to deliver significant growth in value and a sustainable material and growing dividend to shareholders in the years to come. In Lundin Energy we firmly believe that profitable economic growth and environmental benefits go hand in hand.

"The other vital factor I would like to highlight is the great team which has been created; this really is the highest quality team one can dream for, there is no better support network for Nick as he takes the helm in January 2021. I would like to thank all of my colleagues, the Board, shareholders and in particular the Lundin family who has supported me at Lundin Energy for the last 20 years. It has been an amazing journey for the Company and myself and I will continue to be a faithful and passionate Lundin Energy shareholder. For now it's Full Steam Ahead!"

Lundin Energy has grown from an oil and gas exploration company into an experienced Nordic energy developer and operator. We continue to explore new ideas, new concepts and new solutions to maintain our position as an industry leader in production efficiency, sustainability and decarbonisation. (Nasdaq Stockholm: LUNE). For more information, please visit us at www.lundin-energy.com or download our App www.myirapp.com/lundin For definitions and abbreviations, see pages 32 and 33.

OPERATIONAL REVIEW

All the reported numbers and updates in the operational review relate to the nine month period ending 30 September 2020 (reporting period), unless otherwise specified.

Coronavirus Crisis and Low Oil Price Response

The coronavirus crisis, its economic impact and the oil price collapse continues to provide a challenging market backdrop. The main focus of the Company's response has been on reducing the risk of the virus spreading in the operations and safeguarding the well-being of the Company's employees and contractors, whilst at the same time minimising the potential impact on the business. Detailed contingency plans have been established to mitigate the risk, a key element of which is that all personnel visiting the Company's operated production and drilling sites are now tested for the virus before travelling offshore. The Company's offshore activities are continuing with normal manning levels, which means that some activities previously deferred to manage the risk have been brought forward to optimise long-term business outcomes. To date there have been no disruptions to production due to the coronavirus situation.

Lundin Energy has high quality, low cost assets, which are resilient to a low oil price environment. Nevertheless, the Company has taken steps to defer activity and reduce spend, where it does not impact safety, asset integrity or production, in order to further strengthen the near term cash flow and liquidity of the business. Total expenditure reductions and deferrals in 2020 are over MUSD 330 from original guidance, including capital expenditures, operating costs and G&A.

Guidance Update

In May 2020, the Norwegian Government announced the implementation of oil production restriction measures as a response to market over supply, however, the authorities have now increased the fourth quarter 2020 production permits for the Johan Sverdrup, Edvard Grieg and Alvheim fields. Consequently, the Company is increasing estimated fourth quarter 2020 production to approximately 175 Mboepd and raising 2020 full year production guidance to a range of 161 to 163 Mboepd from targeting 157 Mboepd previously. The updated guidance is at the top end of the original guidance range for 2020 of 145 to 165 Mboepd.

2020 guidance	Updated	Previous
Production	161 to 163 Mboepd	Targeting 157 Mboepd
Operating Cost	USD 2.80 per boe	USD 2.80 per boe
Development expenditure	MUSD 650	MUSD 710
Exploration and Appraisal expenditure	MUSD 160	MUSD 140
Decommissioning expenditure	MUSD 50	MUSD 45
Renewables Investments	MUSD 95	MUSD 90

The long term production guidance from 2021 onwards remains between 170 and 180 Mboepd.

Production

First nine months production was 157.6 Mboepd, which was in line with the updated production guidance respecting the reduced production quotas assigned by the Norwegian Government, and was four percent ahead of the mid-point of the original guidance. Strong facilities and reservoir performance at Johan Sverdrup, Edvard Grieg and the Alvheim Area continued during the reporting period.

Operating cost, including netting off tariff income, was USD 2.79 per boe, which is in line with the updated guidance. Full year operating cost guidance remains USD 2.80 per boe.

Production in Mboepd		1 Jan 2020- 30 Sep 2020 9 months	1 Jul 2020- 30 Sep 2020 3 months	1 Jan 2019- 30 Sep 2019 9 months	1 Jul 2019- 30 Sep 2019 3 months	1 Jan 2019- 31 Dec 2019 12 months

Crude oil		146.3	147.0	70.1	72.9	83.5
Gas		11.3	10.5	9.1	9.8	9.8
Total production		157.6	157.5	79.2	82.7	93.3


		1 Jan 2020-	1 Jul 2020-	1 Jan 2019-	1 Jul 2019-	1 Jan 2019-
Production		30 Sep 2020	30 Sep 2020	30 Sep 2019	30 Sep 2019	31 Dec 2019
in Mboepd	WI1	9 months	3 months	9 months	3 months	12 months
Johan Sverdrup	20%	83.3	89.8	–	–	14.0
Edvard Grieg	65%	60.7	56.1	63.6	66.6	63.7
Ivar Aasen	1.385%	0.8	0.7	0.8	0.8	0.8
Alvheim Area	15% - 35%	12.8	11.0	14.8	15.3	14.8

1 Lundin Energy's working interest (WI)

Production from Johan Sverdrup Phase 1 was in line with forecast, reflecting the production restriction measures imposed by the Norwegian Government from June 2020. Four production wells and one water injection well were completed, with results from all five wells in line with or above expectations, and two further development wells are planned to be drilled in 2020. The field is currently producing from 11 wells and reservoir performance continues to be excellent, with total well capacity exceeding the available facilities capacity.

In the first quarter of 2020, it was announced that due to higher established processing capacity, the Phase 1 plateau production rate was increased from 440 thousand barrels of oil per day (Mbopd) gross to 470 Mbopd and as a result full field plateau, when Phase 2 comes on stream, was increased to 690 Mbopd. The increased Phase 1 plateau level of 470 Mbopd was achieved in April 2020, more than two months earlier than scheduled. Now that there is sufficient well capacity, a plan is in place to test the limits of the facility above the current established capacity of 470 Mbopd; this capacity testing is scheduled to occur during the fourth quarter of 2020. Operating costs for the Johan Sverdrup field were USD 1.61 per boe.

Production from the Edvard Grieg field was in line with forecast, reflecting the production restriction measures imposed by the Norwegian Government from June 2020. Reservoir performance continues to exceed expectations, with the water production levels significantly lower than anticipated, which is supported by a 4D seismic survey completed in May 2020 that shows the water injection flood front to be further away from the production wells than predicted, indicating increased oil-in-place in the field. An updated reservoir model has been completed, incorporating these latest results, which supports increased reserves and an extension to the plateau production period. In September 2020, the Company announced a 50 MMboe increase in Edvard Grieg field gross proved plus probable (2P) reserves, lifting the gross 2P ultimate recovery to 350 MMboe. The plateau production period for the Greater Edvard Grieg Area, which also includes the Solveig Phase 1 and Rolvsnes EWT developments, was extended by a further year to late 2023. Due to coronavirus, offshore personnel were down-manned to a minimum level in March 2020, and with the measures taken to limit the risk of infection offshore, a return to normal manning levels commenced in June 2020. In the third quarter 2020, a planned ten-day maintenance shutdown took place, to take advantage of the flexibility offered by the excess production capacity while production was restricted. The planned three well infill well programme at Edvard Grieg is now scheduled to commence in the first quarter of 2021, with the Rowan Viking jack-up rig contracted for this programme. The Edvard Grieg electrification project, which involves the retirement of the existing gas turbine power generation system on the platform, installation of electric boilers to provide process heat and installation of a power cable from Johan Sverdrup to Edvard Grieg, is underway and is expected to be operational in late 2022. Operating costs for the Edvard Grieg field, including netting off tariff income, were USD 3.62 per boe.

Production from the Ivar Aasen field was in line with forecast. In August 2020, drilling commenced on the first of two infill wells that are expected to come on stream in the first quarter of 2021.

Production from the Alvheim Area, consisting of the Alvheim, Volund and Bøyla fields, was in line with forecast reflecting the production restriction measures imposed by the Norwegian Government. In September 2020, drilling was completed on the first of two infill wells in the Alvheim field, where the results from the well are in line with expectations and it is expected on stream in the fourth quarter 2020. Drilling of the second infill well has been deferred to 2021. In the third quarter 2020, a planned maintenance shutdown took place to take advantage of excess production capacity due to the aforementioned production restrictions. Operating costs for the Alvheim Area were USD 5.52 per boe, which was impacted by the under-accruals of subsea equipment repair costs from 2019.

Development

		reserves	start	production
20%	Equinor	2.2 – 3.2 Bn boe1	Q4 2022	690 Mbopd1
65%	Lundin Energy	57 MMboe	Q3 2021	30 Mboepd
80%	Lundin Energy	-	Q3 2021	3 Mboepd
		WI Operator

1 Johan Sverdrup full field

The development expenditure guidance for 2020 is being reduced to MUSD 650 from MUSD 710 due to further cost savings, favourable foreign exchange rates and deferrals.

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. For the subsea wells, a letter of intent has been signed for the Deepsea Atlantic semi-submersible rig, which was the same rig used for the Phase 1 pre-drilled wells. The Johan Sverdrup field reserves are in the range 2.2 to 3.2 billion boe and the ambition of the partners in the field, is to achieve a recovery factor of more than 70 percent. Due to higher established processing capacity for Phase 1 of the development, the full field plateau, when Phase 2 comes on stream will be at the increased level of 690 Mbopd. Full field breakeven oil price, including past investments, is estimated at below USD 20 per boe. The PDO for Phase 2 was approved in May 2019.

The Phase 2 capital expenditure is estimated at gross NOK 41 billion (nominal), which is unchanged from the Phase 2 PDO estimate. Construction is ongoing on the second processing platform topsides and jacket, the new modules to be installed on the existing Riser Platform and the subsea facilities. The project experienced reduced progress levels from mid-March 2020 due to the coronavirus situation, but activity has since returned to normal levels and progress is now over 45 percent complete, with scheduled first oil in the fourth quarter of 2022 being maintained. Overall, the Johan Sverdrup Phase 2 project is on schedule and within budget.

Johan Sverdrup is being operated with power supplied from shore and is one of the lowest CO2 emitting offshore field in the world with CO2 emissions of approximately 0.2 kg per boe (below the original forecast of approximately 0.7 kg per boe). The project also includes expansion of the power from shore facilities for Phase 2, which includes additional capacity for the Utsira High Power grid, including for the Edvard Grieg field.

Greater Edvard Grieg Area Tie-Back Projects

Solveig Phase 1 is the first Edvard Grieg subsea tie-back development and will contribute to keeping the Edvard Grieg platform filled to capacity for an extended time period. Phase 1 gross 2P reserves are estimated at 57 MMboe and will be developed with three oil production wells and two water injection wells, achieving gross peak production of 30 Mboepd. The PDO for Solveig Phase 1 was approved in June 2019. The capital cost estimate for the development is within the PDO estimate of MUSD 810 gross, with a breakeven oil price of below 30 USD per boe. The potential for further phases of development, which will capture the upside potential in the discovered resources, will be de-risked by production performance from Phase 1.

The Rolvsnes Extended Well Test (EWT) project, which was approved by the authorities in July 2019, will be conducted 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 a potential Rolvsnes full field development. The project is being implemented together with the Solveig project to take advantage of contracting and implementation synergies.

Both Edvard Grieg Area tie-back projects progressed as planned to March 2020, when the project activities were re-scheduled to manage the coronavirus risk, resulting in the deferral of first oil for both projects. These project deferrals have no negative impact on the Company's net production in 2021 and 2022, as the Edvard Grieg field has excess well potential to fill the available facilities capacity. Progress on the Edvard Grieg topsides modifications, which are well advanced, was slowed for a period, however as the coronavirus limitations have been eased the activity has been re-mobilised. Installation of the subsea facilities commenced in March 2020 and all production and injection pipelines and the satellite well head structures have now been installed. The start of development drilling operations with the West Bollsta semi-submersible rig, is now scheduled for the first quarter of 2021. Solveig Phase 1 project progress is over 45 percent complete and the Rolvsnes EWT project is approximately 70 percent complete. The Solveig Phase 1 and Rolvsnes EWT deferred first oil is unchanged from the third quarter of 2021.

Appraisal

2020 appraisal well programme

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

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

In June 2020, the Norwegian Government, to stimulate activity, announced temporary tax incentives that apply to PDO's submitted for approval before the end of 2022. These tax incentives significantly improve project economics and the Company has up to nine potential projects that could be accelerated to benefit from this opportunity. The Company's net resources for these potential projects, inclusive of the acquisition announced in September 2020 of an interest in the Wisting field, totals over 190 MMboe, with the main projects being Solveig Phase 2/Segment D, Rolvsnes Full Field, Iving, Alta, Wisting and the Alvheim Area projects of Kobra East/Gekko and Frosk. The plan is to accelerate appraisal activities and field development studies for all of these potential projects with the aim of maturing them to PDO within the time-line of the tax incentives.

Exploration

2020 exploration well programme

Licence	Operator	WI	Well	Spud Date	Result
PL917	ConocoPhillips	20%	Hasselbaink	January 2020	Dry
PL820S	MOL	40%	Evra/Iving	November 2019	Two oil & gas discoveries
PL6091/PL1027	Lundin Energy	40%	Polmak	October 2020	Ongoing
PL960	Equinor	20%	Spissa	Fourth quarter 2020
PL533	Lundin Energy	40%	Bask	Fourth quarter 2020
PL981	Lundin Energy	60%	Merckx	Fourth quarter 2020

¹ Lundin Energy's working interest in Licence PL609 will increase to 55% on closing of the Idemitsu Petroleum Norge transaction and consequently the Company's working interest in the Polmak exploration well will increase to 47.5%

The scaled back 2020 exploration drilling programme involves six wells, of which two have been completed. Discoveries at the Evra/Iving prospects have been made so far in 2020 and the remaining four exploration wells will be drilled in the fourth quarter targeting net unrisked resources of over 350 MMboe. With the results of the Merckx exploration well now anticipated in early 2021. Three of the remaining wells are operated by Lundin Energy and will be drilled by the West Bollsta semi-submersible rig. The exploration and appraisal expenditure guidance for 2020 is being increased to MUSD 160 from MUSD 140 due to activity changes.

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

In October 2020, drilling commenced on the Polmak prospect in PL609/PL1027 located north of the Alta discovery on the Loppa High in the Southern Barents Sea. The main reservoir target at Polmak are Triassic age Kobbe sandstones, with estimated gross unrisked prospective resources of 400 MMbo.

Decarbonisation Strategy and Renewable Energy Projects

In January 2020, Lundin Energy announced its Decarbonisation Strategy with the target to become carbon neutral across its operations by 2030. Lundin Energy's net carbon intensity for all assets was 2.7 kg CO2 per boe for the reporting period, which is approximately 50 percent lower than the 2019 average. This reduction is largely due to Johan Sverdrup coming on stream, which had a carbon intensity during the reporting period of approximately 0.2 kg CO2 per boe, and a strong focus within the business of minimising emissions. The full year forecast for net carbon intensity is similar to the first nine months performance, which is well within the Company's 2020 target of less than 4 kg CO2 per boe. Lundin Energy's carbon emissions performance is set to improve further with the Edvard Grieg platform being fully electrified in late 2022, when the average net carbon intensity for all the Company's producing assets is expected to be below 2 kg CO2 per boe, approximately one-tenth of the industry average.

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

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

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

Lundin Energy's total investment commitments in renewable energy projects amounts to approximately MUSD 150 over the period 2020/2021. The renewable expenditure guidance for 2020 is being increased to MUSD 95 from MUSD 90.

Decommissioning

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

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

The decommissioning expenditure guidance for 2020 is being increased to MUSD 50 from MUSD 45. Following completion of Brynhild and Gaupe decommissioning, the Company has no further planned decommissioning spend until around 2035.

Licence Awards and Transactions

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

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

In September 2020, Lundin Energy entered into a sales and purchase agreement with Vår Energi AS, involving the acquisition of a 50 percent working interest in PL229E. The transaction is expected to be completed within the fourth quarter of 2020.

In September 2020, Lundin Energy applied for licences in the 2020 APA licensing round where awards are anticipated in early 2021.

In October 2020, Lundin Energy entered into a sales and purchase agreement with Idemitsu Petroleum Norge AS involving the acquisition of a 10 percent working interest in the major Wisting oil discovery in licences PL537 and PL537B. Wisting is estimated to contain 500 MMbo of gross resources and is scheduled to be one of the next Barents Sea production hubs. Equinor, the operator of Wisting in the development phase, is targeting a PDO by end 2022, to benefit from the temporary tax incentives established by the Norwegian Government in June 2020. The transaction also involves a 15 percent working interest in PL609, PL609B, PL609C, PL609D and PL851, which increases Lundin Energy's working interest from 40 to 55 percent in the Alta discovery and from 40 to 47.5 percent in the Polmak exploration well, both operated by the Company. The transaction, which is effective from January 2020, adds estimated net contingent resources of approximately 70 MMboe for a cash consideration of MUSD 125, and is subject to usual Norwegian regulatory approvals, with completion expected in the fourth quarter of 2020.

Currently the Company holds 80 licences in Norway, which is an increase of approximately 20 percent from the beginning of 2019.

Health, Safety and Environment

In May 2020, one person was seriously injured during an incident on a contractor operated vessel, that was working on behalf of the Company on the subsea installation activities for the Edvard Grieg tie-back projects. The incident has been thoroughly investigated and mitigating measures implemented. During the reporting period, one further lost time incident and three medical treatment incidents occurred, resulting in a Lost Time Incident Rate of 1.6 per million hours worked and a Total Recordable Incident Rate of 4.0 per million hours worked. There were no material environmental incidents during the reporting period.

FINANCIAL REVIEW

Result

The operating profit for the reporting period amounted to MUSD 932.6 (MUSD 1,588.2), with the decrease compared to the comparative period mainly driven by a MUSD 756.7 after tax accounting gain on the sale of 2.6 percent of Johan Sverdrup during the comparative period. The operating profit for the comparative period excluding this accounting gain amounted to MUSD 831.5 with the increase during the reporting period mainly driven by higher sales volumes and lower exploration costs. Sales volumes almost doubled compared to the comparative period as a result of the startup of production from the Johan Sverdrup field in October 2019, but this was partly offset by lower oil prices and higher depletion charges during the reporting period.

The net result for the reporting period amounted to MUSD 80.5 (MUSD 669.6), representing earnings per share of USD 0.28 (USD 2.05). Net result was impacted by a foreign currency exchange loss during the reporting period of MUSD 85.2 (MUSD 237.7) and a MUSD 756.7 after tax accounting gain in the comparative period on the sale of 2.6 percent of Johan Sverdrup. Adjusted net result for the reporting period amounted to MUSD 193.1 (MUSD 173.8), representing adjusted earnings per share of USD 0.68 (USD 0.53). Adjusted net result separates out the effects of accounting gains/losses from asset sales, loan modification gains, foreign currency exchange results, impairment charges and the tax impacts from these items and better reflects the net result generated by the Company's operational performance for the reporting period.

Earnings before interest, tax, depletion and amortisation (EBITDA) for the reporting period amounted to MUSD 1,431.8 (MUSD 1,222.9) representing EBITDA per share of USD 5.04 (USD 3.75), with the increase compared to the comparative period mainly caused by higher sales volumes because of the startup of production from the Johan Sverdrup field, partly offset by lower oil prices. Cash flow from operating activities (CFFO) for the reporting period amounted to MUSD 1,251.3 (MUSD 985.3), representing CFFO per share of USD 4.40 (USD 3.02) with the increase compared to the comparative period, again impacted by higher sales volumes, partly offset by lower oil prices but further positively impacted by working capital changes during the reporting period. Free cash flow for the reporting period amounted to MUSD 545.7 (MUSD 1,117.9), representing free cash flow per share of USD 1.92 (USD 3.42), with the decrease compared to the comparative period mainly impacted by the cash inflow of MUSD 959.0 from the sale of 2.6 percent of Johan Sverdrup during the comparative period. Free cash flow for the comparative period excluding this cash inflow amounted to MUSD 158.9 with the increase during the reporting period mainly impacted by higher CFFO and lower investing activities during the reporting period.

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

Norwegian tax changes

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

Changes in the Group

In January 2020, Lundin Energy completed a transaction with OX2 AB (OX2) to acquire a 100 percent interest in the Metsälamminkangas (MLK) wind farm project, in mid Finland. In March 2020, Lundin Energy completed a transaction with Sval Energi AS (Sval), a portfolio company of HitecVision, to farm down 50 percent of its MLK wind farm project. MLK will produce around 400 GWh per annum gross, once it is fully operational in early 2022, from 24 onshore wind turbines. The MLK operations will be managed by OX2. The investment, including the acquisition cost, is approximately MUSD 200 gross over 2020 and 2021 (MUSD 100 net to Lundin Energy) and the project is anticipated to be free cash flow positive from 2022. The 50 percent interest in MLK is recognised as an investment in a joint venture in the consolidated accounts of the Group.

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

Revenue and other income

Revenue and other income for the reporting period amounted to MUSD 1,784.7 (MUSD 2,199.0) and was comprised of net sales of oil and gas and other revenue as detailed in Note 1.

Net sales of oil and gas for the reporting period amounted to MUSD 1,759.8 (MUSD 1,418.3). The average price achieved by Lundin Energy for a barrel of oil equivalent from own production, amounted to USD 36.31 (USD 61.14) and is detailed in the following table. The average Dated Brent price for the reporting period amounted to USD 41.06 (USD 64.59) per barrel and USD 42.94 (USD 62.00) for the third quarter.

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

Sales from own production Average price per boe expressed in USD	1 Jan 2020- 30 Sep 2020 9 months	1 Jul 2020- 30 Sep 2020 3 months	1 Jan 2019- 30 Sep 2019 9 months	1 Jul 2019- 30 Sep 2019 3 months	1 Jan 2019- 31 Dec 2019 12 months
Crude oil sales
– Quantity in Mboe	38,822.4	12,022.5	19,039.0	7,028.0	29,769.7
– Average price per bbl	38.07	42.94	65.29	61.44	65.16
Gas and NGL sales – Quantity in Mboe – Average price per boe	4,231.7 20.15	1,418.1 21.26	2,780.2 32.74	788.0 23.87	4,235.7 31.77
Total sales – Quantity in Mboe – Average price per boe	43,054.1 36.31	13,440.6 40.65	21,819.2 61.14	7,816.0 57.65	34,005.4 61.00

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

Net sales of crude oil from third party activities for the reporting period amounted to MUSD 196.6 (MUSD 84.3) and consisted of crude oil purchased from outside the Group by Lundin Energy Marketing SA and sold to the market. Revenue from sale of oil and gas are recognised when control of the products is transferred to the customer.

Other income for the reporting period amounted to MUSD 24.9 (MUSD 24.0) and mainly included tariff income of MUSD 17.9 (MUSD 19.5), which is due to net income from Ivar Aasen tariffs paid to Edvard Grieg. Other income for the reporting period also included MUSD 0.8 (MUSD –) relating to Dated Brent differential derivatives.

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

Production costs

Production costs including under/over lift movements and inventory movements for the reporting period amounted to MUSD 139.2 (MUSD 118.6) and are detailed in Note 2. The total production cost per barrel of oil equivalent produced is detailed in the table below:

	1 Jan 2020-	1 Jul 2020-	1 Jan 2019-	1 Jul 2019-	1 Jan 2019-
Production costs	30 Sep 2020 9 months	30 Sep 2020 3 months	30 Sep 2019 9 months	30 Sep 2019 3 months	31 Dec 2019 12 months
Cost of operations
– In MUSD	101.9	32.4	81.9	25.5	118.1
– In USD per boe	2.36	2.24	3.79	3.35	3.47
Tariff and transportation expenses
– In MUSD	36.4	13.5	30.7	10.9	46.3
– In USD per boe	0.84	0.93	1.42	1.44	1.36
Operating costs
– In MUSD	138.3	45.9	112.6	36.4	164.4
– In USD per boe1	3.20	3.17	5.21	4.79	4.83
Change in under/over lift position
– In MUSD	-3.9	-12.0	2.6	4.2	-0.9
– In USD per boe	-0.09	-0.82	0.12	0.54	-0.03
Change in inventory position
– In MUSD	0.4	0.5	0.3	0.0	-2.8
– In USD per boe	0.01	0.03	0.02	0.00	-0.08
Other
– In MUSD	4.4	1.5	3.1	1.0	4.1
– In USD per boe	0.10	0.11	0.14	0.13	0.12
Production costs
– In MUSD	139.2	35.9	118.6	41.6	164.8
– In USD per boe	3.22	2.49	5.49	5.46	4.84

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

1 The numbers in this table are excluding tariff income netting. Lundin Energy's operating cost for the reporting period of USD 3.20 (USD 5.21) per barrel is reduced to USD 2.79 (USD 4.31) when tariff income is netted off. The operating cost for the third quarter of USD 3.17 (USD 4.79) per barrel is reduced to USD 2.80 (USD 3.97) when tariff income is netted off.

The total cost of operations for the reporting period amounted to MUSD 101.9 (MUSD 81.9) and the total cost of operations excluding operational projects amounted to MUSD 97.2 (MUSD 74.4). The increase compared to the comparative period related to the start up of production from the Johan Sverdrup field in October 2019, partly offset by a weaker Norwegian Kroner.

The cost of operations per barrel for the reporting period amounted to USD 2.36 (USD 3.79), including operational projects and USD 2.25 (USD 3.44) excluding operational projects. The lower unit costs compared to the comparative period are mainly relating to the start up of the Johan Sverdrup field, which has a lower unit operating cost, in addition to a weaker Norwegian Kroner.

Tariff and transportation expenses for the reporting period amounted to MUSD 36.4 (MUSD 30.7) or USD 0.84 (USD 1.42) per barrel. The decrease on a per barrel basis compared to the comparative period, is driven by the start up of production from the Johan Sverdrup field in October 2019, in addition to a weaker Norwegian Kroner.

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 -3.9 (MUSD 2.6) in the reporting period due to the timing of the cargo liftings compared to production. Sales quantities and production quantities are detailed in the table below:

Change in over/underlift position In Mboepd	1 Jan 2020- 30 Sep 2020 9 months	1 Jul 2020- 30 Sep 2020 3 months	1 Jan 2019- 30 Sep 2019 9 months	1 Jul 2019- 30 Sep 2019 3 months	1 Jan 2019- 31 Dec 2019 12 months
Production volumes	157.6	157.5	79.2	82.7	93.3
Johan Sverdrup inventory movements	–	–	–	–	-0.7
Production volumes excluding inventory movements	157.6	157.5	79.2	82.7	92.6
Sales volumes from own production	157.1	146.1	79.9	85.0	93.2
Change in overlift position	0.5	11.4	-0.7	-2.3	-0.6

Other costs for the reporting period amounted to MUSD 4.4 (MUSD 3.1) and related to the business interruption insurance.

Depletion and decommissioning costs

Depletion and decommissioning costs for the reporting period amounted to MUSD 446.8 (MUSD 301.6) at an average rate of USD 10.35 (USD 13.95) per barrel and are detailed in Note 3. The lower depletion costs for the reporting period compared to the comparative period, is due to the start up of production from the Johan Sverdrup field at a lower depletion rate per barrel. The depletion costs are further positively impacted by a lower depletion rate per barrel in USD terms, as the depletion rate per barrel is calculated in Norwegian Kroner with the Norwegian Kroner having weakened against the USD compared to the comparative period.

Exploration costs

Exploration costs expensed in the income statement for the reporting period amounted to MUSD 47.3 (MUSD 84.7) and are detailed in Note 3. Exploration and appraisal costs are capitalised as they are incurred. When exploration and appraisal drilling is unsuccessful, the capitalised costs are expensed. All capitalised exploration costs are reviewed on a regular basis and are expensed when facts and circumstances suggest that the carrying value of an exploration and evaluation asset may exceed its recoverable amount.

Purchase of crude oil from third parties

Purchase of crude oil from third parties for the reporting period amounted to MUSD 193.3 (MUSD 84.3) and related to crude oil purchased from outside the Group.

General, administrative and depreciation expenses

The general administrative and depreciation expenses for the reporting period amounted to MUSD 25.5 (MUSD 21.6), which included a charge of MUSD 3.2 (MUSD 3.4) in relation to the Group's long-term incentive plans (LTIP), see also Remuneration section on page 14. Fixed asset depreciation expenses for the reporting period amounted to MUSD 5.2 (MUSD 5.1).

Finance income

Finance income for the reporting period amounted to MUSD 1.0 (MUSD 23.8) and is detailed in Note 4.

Finance costs

Finance costs for the reporting period amounted to MUSD 258.2 (MUSD 366.6) and are detailed in Note 5.

The net foreign currency exchange loss for the reporting period amounted to MUSD 85.2 (MUSD 237.7). Foreign exchange movements occur on the settlement of transactions denominated in foreign currencies and the revaluation of working capital and loan balances to the prevailing exchange rate, at the balance sheet date where those monetary assets and liabilities are held in currencies other than the functional currencies of the Group's reporting entities. Lundin Energy is exposed to exchange rate fluctuations relating to the relationship between US Dollar and other currencies. Lundin Energy has entered into derivative financial instruments to address this exposure for exchange rate fluctuations for capital expenditure amounts and Corporate and Special Petroleum Tax amounts. For the reporting period, the net realised exchange loss on these settled foreign exchange instruments amounted to MUSD 54.9 (MUSD 46.5) and a further non-cash exchange loss of MUSD 2.1 was charged to the income statement for the reporting period due to non-effective hedge treatment of certain of the future foreign exchange contracts.

The US Dollar weakened four percent against the Euro during the reporting period, resulting in a net foreign currency exchange gain on the US Dollar denominated external loan, which is borrowed by a subsidiary using Euro as functional currency. In addition, the Norwegian Krone weakened 13 percent against the Euro in the reporting period, generating a largely non-cash net foreign currency exchange loss on an intercompany loan balance denominated in Norwegian Krone.

Interest expenses for the reporting period amounted to MUSD 77.9 (MUSD 54.7) and represented the portion of interest charged to the income statement. An additional amount of interest of MUSD 18.0 (MUSD 79.3), associated with the funding of the Norwegian development projects was capitalised in the reporting period. The total interest expense for the reporting period decreased compared to the comparative period as a result of a lower LIBOR rate since the second quarter of 2020 and partly offset by higher average debt relative to the comparative period.

The result on interest rate hedge settlements amounted to a loss of MUSD 29.3 (gain of MUSD 22.5), as a result of the lower LIBOR rate.

The amortisation of the deferred financing fees for the reporting period amounted to MUSD 12.3 (MUSD 15.8) and related mainly to the fees incurred in establishing the reserve-based lending facility. The fees in relation to the reserve-based lending facility are being expensed over the expected life of that facility.

Loan facility commitment fees for the reporting period amounted to MUSD 8.7 (MUSD 8.9) and related mainly to the higher outstanding loan under the reserve-based lending facility following the share redemption in August 2019, which resulted in lower commitment fees under the reserve-based lending facility. The loan facility commitments fees also include commitment fees in relation to the revolving credit facility for the financing of the renewable power projects and the MUSD 340 unsecured corporate facility.

The unwinding of the loan modification gain for the reporting period amounted to MUSD 29.1 (MUSD 31.4) and related to the expensing of the accounting gain from the re-negotiated improved borrowing terms for the reserve-based lending facility over the period of usage of the facility.

Share in result of joint ventures and associated company

Share in result of joint ventures and associated company for the reporting period amounted to MUSD 0.0 (MUSD -1.3) and related to the 50 percent non-operated interest in the Leikanger hydropower project in Norway, with the project commencing production during the second quarter 2020. The loss in the comparative period related to the share in the result of the investment in Mintley Caspian Ltd. with this company currently being liquidated.

Tax

The overall tax charge for the reporting period amounted to MUSD 594.9 (MUSD 574.5) and is detailed in Note 6.

The current tax charge for the reporting period amounted to MUSD 251.2 (MUSD 80.5) and mainly related to Norway. The current tax charge for Norway for the reporting period related to both Corporate Tax and Special Petroleum Tax (SPT). The SPT tax losses were fully utilized during the fourth quarter of 2019, which resulted in increased current tax charges for the reporting period and the current tax charge for Norway for the comparative period related therefore, to Corporate Tax only. The paid tax installments in Norway during the reporting period amounted to MUSD 89.7, which has in combination with the current tax charge for the reporting period and exchange rate movements resulted in an increase in current tax liabilities compared to the end of last year from MUSD 343.3 to MUSD 479.0. On 19th June 2020 certain temporary changes in the Norwegian Petroleum Tax Law were enacted. The temporary changes allow investments incurred in 2020 and 2021 to be fully deducted against SPT in the year of investment compared to a six year linear depreciation for the ordinary tax regime. There is a further deduction available against the SPT in the form of an uplift. For the years 2020 and 2021, the uplift has been changed to 24 percent of the investment incurred in the year and is fully deductible in the year the investment is incurred, versus the previous uplift treatment which stipulated that the investment incurred during the year qualified for an uplift of 5.2 percent annually over four years (i.e. 20.8 percent uplift). The temporary changes in the Petroleum Tax Law also apply for Plan of Development and Operations submitted within 2022. These tax rules changes resulted in a reduction on current taxes for the reporting period and an increase in deferred tax for the reporting period.

The deferred tax charge for the reporting period amounted to MUSD 343.7 (MUSD 494.0) and related to Norway. A deferred tax amount arises primarily where there is a difference in depletion for tax and accounting purposes, with the deferred tax charge increased for the reporting period due to the temporary tax changes for the Special Petroleum Tax in Norway as outlined above.

The Group operates in various countries and fiscal regimes where corporate income tax rates are different from the regulations in Sweden. Corporate income tax rates for the Group vary between 21.4 and 78 percent. The effective tax rate for the reporting period is affected by items which do not receive a full tax credit such as the reported net foreign currency exchange results, Norwegian financial items and by the uplift allowance applicable in Norway for development expenditures against the offshore tax regime. The effective tax rate for the reporting period was mainly impacted by the reported foreign currency exchange loss and the effective tax rate on the adjusted net results for the reporting period amounted to 76 percent.

Balance Sheet

Non-current assets

Oil and gas properties amounted to MUSD 5,180.1 (MUSD 5,473.2) and are detailed in Note 7.

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

	1 Jan 2020-	1 Jul 2020-	1 Jan 2019-	1 Jul 2019-	1 Jan 2019-
Development expenditure	30 Sep 2020	30 Sep 2020	30 Sep 2019	30 Sep 2019	31 Dec 2019
in MUSD	9 months	3 months	9 months	3 months	12 months
Norway	491.4	139.5	498.0	140.8	672.3
Development expenditure	491.4	139.5	498.0	140.8	672.3

Development expenditure of MUSD 491.4 (MUSD 498.0) was incurred in Norway during the reporting period, primarily on the Johan Sverdrup field. In addition an amount of MUSD 18.0 (MUSD 79.3) of interest was capitalised.

Exploration and appraisal expenditure in MUSD	1 Jan 2020- 30 Sep 2020 9 months	1 Jul 2020- 30 Sep 2020 3 months	1 Jan 2019- 30 Sep 2019 9 months	1 Jul 2019- 30 Sep 2019 3 months	1 Jan 2019- 31 Dec 2019 12 months
Norway	85.8	21.3	236.3	53.0	298.4
Exploration and appraisal expenditure	85.8	21.3	236.3	53.0	298.4

Exploration and appraisal expenditure of MUSD 85.8 (MUSD 236.3) was incurred in Norway during the reporting period, primarily for the exploration and appraisal wells as summarized on page 6.

Other tangible fixed assets amounted to MUSD 42.0 (MUSD 49.4) and are detailed in Note 8.

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

Investments in joint ventures amounted to MUSD 84.3 (MUSD –) and related to the 50 percent interest held by Lundin Energy in the Metsälamminkangas (MLK) wind farm project in Finland and the Leikanger hydropower project in Norway, see also page 6.

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

Renewables investments in MUSD	1 Jan 2020- 30 Sep 2020 9 months	1 Jul 2020- 30 Sep 2020 3 months	1 Jan 2019- 30 Sep 2019 9 months	1 Jul 2019- 30 Sep 2019 3 months	1 Jan 2019- 31 Dec 2019 12 months
MLK Windfarm – Finland	35.2	5.4	–	–	–
Leikanger Hydropower – Norway	44.9	–	–	–	–
Renewables investments	80.1	5.4	–	–	–

Financial assets amounted to MUSD 13.4 (MUSD 14.3) and are detailed in Note 9. The sale of 2.6 percent of Johan Sverdrup during 2019 included a contingent consideration based on future reserve reclassifications and is due in 2026. This contingent consideration was fair valued by the Company and amounted to MUSD 12.6 (MUSD 12.4).

Trade and other receivables amounted to MUSD 15.5 (MUSD –) and related to prepayment with a long-term nature and are detailed in Note 10.

Current assets

Inventories amounted to MUSD 42.1 (MUSD 40.7) and included both well supplies and hydrocarbon inventories.

Trade and other receivables amounted to MUSD 289.0 (MUSD 349.5) and are detailed in Note 10. Trade receivables, which are all current, amounted to MUSD 231.8 (MUSD 305.1) with the decrease caused by the lower oil prices and lower sales volumes in September 2020. Underlift amounted to MUSD 11.0 (MUSD 2.0) and was attributable to an underlift position on the producing fields, mainly relating to oil from the Johan Sverdrup and Edvard Grieg fields. Joint operations debtors relating to various joint venture receivables amounted to MUSD 12.9 (MUSD 11.4). Prepaid expenses and accrued income amounted to MUSD 27.0 (MUSD 23.9) and represented mainly prepaid operational and insurance expenditure. Other current assets amounted to MUSD 6.3 (MUSD 7.1).

Cash and cash equivalents amounted to MUSD 129.2 (MUSD 85.3). Cash balances are mainly held to meet ongoing operational funding requirements.

Non-current liabilities

Financial liabilities amounted to MUSD 3,180.7 (MUSD 3,888.4) and are detailed in Note 11. Bank loans amounted to MUSD 3,250.0 (MUSD 4,000.0) and related to the long-term portion of the outstanding bank loans with the short-term portion classified as current liabilities. Capitalised financing fees relating to the establishment of the facilities amounted to MUSD 24.5 (MUSD 37.1) and are being amortised over the expected life of the facilities. The capitalised loan modification gain relating to the re-negotiated improved borrowing terms for the lending facility during 2018, amounted to MUSD 69.8 (MUSD 105.6) and are being amortised over the expected life of the facility. The lease commitments amounted to MUSD 25.0 (MUSD 31.1) and related to the long-term portion of the lease commitments under IFRS 16. The short-term portion of the lease commitments was classified as current liabilities.

Provisions amounted to MUSD 500.3 (MUSD 528.1) and are detailed in Note 12. The provision for site restoration amounted to MUSD 496.5 (MUSD 522.2) and related to the long-term portion of the future decommissioning obligations. The short-term portion of the future decommissioning obligations was classified as current liabilities and amounted to MUSD 16.6 (MUSD 49.2). The decrease in site restoration is mainly caused by the weakening of the Norwegian Kroner during the reporting period and the commencement of decommissioning work on the Brynhild field.

Deferred tax liabilities amounted to MUSD 2,571.5 (MUSD 2,412.7). The provision mainly arises on the excess of book value over the tax value of oil and gas properties. Deferred tax assets are netted off against deferred tax liabilities where they relate to the same jurisdiction.

Derivative instruments amounted to MUSD 200.4 (MUSD 110.8) and related to the marked-to-market loss on outstanding interest rate and currency hedge contracts due to be settled after twelve months.

Current liabilities

Current financial liabilities amounted to MUSD 591.0 (MUSD 97.5) and are detailed in Note 11. Current financial liabilities related to the short-term portion of the outstanding bank loans and lease commitments. Current financial liabilities related for MUSD 586.0 (MUSD 92.0) to the short-term portion of the outstanding bank loans.

Dividends amounted to MUSD 142.9 (MUSD 106.0) and related to the cash dividend approved by the AGM held on 31 March 2020 in Stockholm, which will be paid in quarterly installments.

Trade and other payables amounted to MUSD 240.7 (MUSD 177.4) and are detailed in Note 13. Overlift amounted to MUSD 6.7 (MUSD 0.9) and was attributable to an overlift position mainly in relation to oil from the Alvheim Area. Joint operations creditors and accrued expenses amounted to MUSD 119.4 (MUSD 133.6) and related to activity in Norway. Other accrued expenses amounted to MUSD 28.3 (MUSD 16.6) and other current liabilities amounted to MUSD 3.1 (MUSD 8.5).

Derivative instruments amounted to MUSD 123.2 (MUSD 33.2) and related to the marked-to-market loss on outstanding interest rate and currency hedge contracts due to be settled within twelve months.

Current tax liabilities amounted to MUSD 479.0 (MUSD 343.3) and related mainly to Norway. The current tax liabilities have increased from MUSD 385.8 as of the end of the second quarter 2020 to MUSD 479.0 as of the end of the reporting period mainly due to cash taxes payments of MUSD 37.4 during the third quarter 2020 and a current tax charge for the third quarter of MUSD 121.7.

Current provisions amounted to MUSD 19.6 (MUSD 55.9) and are detailed in Note 12. The short-term portion of the future decommissioning obligations amounted to MUSD 16.6 (MUSD 49.2) mainly relating to the Brynhild field. The short-term portion of the provision for Lundin Energy's Unit Bonus Plan amounted to MUSD 3.0 (MUSD 6.7).

Parent Company

The business of the Parent Company is investment in and management of oil and gas assets and renewable energy projects. The net result for the Parent Company for the reporting period amounted to MSEK 2,700.3 (MSEK 18,965.6). The net result for the reporting period included MSEK 2,867.8 (MSEK 19,148.4) financial income as a result of received dividends from a subsidiary. The net result excluding received dividends amounted to MSEK -167.5 (MSEK -182.8).

The net result for the reporting period included general and administrative expenses of MSEK 175.7 (MSEK 170.5) and net finance expenses of MSEK 4.1 (MSEK 21.8) when excluding the received dividends as mentioned above.

Pledged assets of MSEK 55,118.9 (MSEK 55,118.9) relate to the carrying value of the pledge of the shares in respect of the reserve-based lending facility entered into by its wholly-owned subsidiary Lundin Energy Holding BV, see also the Liquidity section below.

Due to the oil price collapse during the first half of 2020, the Parent Company performed a full impairment test in relation to the shares held in Lundin Energy Holding B.V. by the end of the second quarter 2020. Based on this impairment test, no impairment was recognized by the Parent Company but the impairment headroom was reduced as a consequence of a lower long-term oil price being applied.

Related Party Transactions

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

Liquidity

In February 2016, Lundin Energy entered into a committed seven year senior secured reserve-based lending facility of USD 5.0 billion. The facility was amended during the second quarter of 2018, resulting in the interest rate margin over LIBOR being reduced from 3.15 percent to a current rate of 2.5 percent (2.25 percent). The facility is secured against certain cash flows generated by the Group. The amount available under the facility is recalculated every twelve months, based upon the calculated cash flow generated by certain producing fields and fields under development, at an oil price and economic assumptions agreed with the banking syndicate providing the facility. The facility is secured by a pledge over the shares of certain Group companies, a pledge over the Company's working interest in some production licences and a charge over some of the bank accounts of the pledged companies. The size of the committed facility is currently USD 4.75 billion and will reduce to USD 4.0 billion as per 1 January 2021 and to USD 3.25 billion as per 1 July 2021. Lundin Energy's intention is to refinance the external loan facility within the coming 9-months period and is expecting to achieve such refinancing on competitive terms given the financial robustness of the Company and the low cost base of its assets. The Company received on 29 July 2020 its inaugural public credit rating from S&P Global Rating, with a rating of BBB- with a stable outlook.

In January 2020, Lundin Energy entered into a revolving credit facility amounting to MUSD 260 for the financing of the renewable power projects with a current interest rate margin over LIBOR of 1.25 percent. The facility size was reduced to MUSD 160 in March 2020 following the farm down of 50 percent of the Metsälamminkangas (MLK) wind farm project to Sval.

In April 2020, Lundin Energy entered into an unsecured corporate facility amounting to MUSD 340 as a prudent measure due to the oil market uncertainties. The facility, which remains undrawn, has a current interest rate margin over LIBOR of 2.6 percent.

Contingent liabilities

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

Subsequent Events

During October 2020, Lundin Energy rolled forward to 2021 certain foreign currency exchange contracts with an original settlement date in 2020 to buy MNOK 296 against an average contractual exchange rate of NOK 8.72:USD 1.

Share Data

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

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

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

The AGM of Lundin Energy held on 31 March 2020 in Stockholm approved a cash dividend distribution for the year 2019 of USD 1.00 per share, to be paid in quarterly installments of USD 0.25 per share. Before payment, each quarterly dividend of USD 0.25 per share shall be converted into a SEK amount, and paid out in SEK, based on the USD to SEK exchange rate published by Sweden's central bank (Riksbanken) four business days prior to each record date (rounded off to the nearest whole SEK 0.01 per share). The final USD equivalent amount received by the shareholders may therefore slightly differ depending on what the USD to SEK exchange rate is on the date of the dividend payment. Based on the number of shares outstanding, excluding own shares held by the Company, the approved dividend distribution amounted to MSEK 2,867.8, equaling MUSD 284.1 based on the exchange rate on the date of AGM approval.

The first dividend payment was made on 7 April 2020, the second dividend payment was made on 8 July 2020 and the third dividend payment was made on 7 October 2020. The fourth dividend payment is expected to be paid around 8 January 2021, with an expected record date of 4 January 2021 and an expected ex-dividend date of 30 December 2020.

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 2019 dividend has been set to a cap of SEK 5.188 billion (i.e., SEK 1.297 billion per quarter). If the total dividend would exceed the cap of SEK 5.188 billion, the dividend will be automatically adjusted downwards so that the total dividend corresponds to the cap of SEK 5.188 billion.

Remuneration

Lundin Energy's principles for remuneration and details of the long-term incentive plans are provided in the Company's 2019 Annual Report and in the materials provided to shareholders in respect of the 2020 AGM, available on www.lundin-energy.com

Unit Bonus Plan

The number of units relating to the awards made in 2018, 2019 and 2020 under the Unit Bonus Plan outstanding as at 30 September 2020 were 70,123, 123,951 and 267,600 respectively.

Performance Based Incentive Plan

The AGM 2020 resolved a long-term performance based incentive plan in respect of Group management and a number of key employees. The plan is effective from 1 July 2020 and the 2020 award is accounted for from the second half of 2020. The total outstanding number of awards at 30 September 2020 was 393,113 and the awards vest over three years from 1 July 2020 subject to certain performance conditions being met. Each original award was fair valued at the date of grant at SEK 147.10 using an option pricing model.

The 2019 plan is effective from 1 July 2019 and the total outstanding number of awards at 30 September 2020 was 310,330 and the awards vest over three years from 1 July 2019 subject to certain performance conditions being met. Each original award was fair valued at the date of grant at SEK 169.00 using an option pricing model.

The 2018 plan is effective from 1 July 2018 and the total outstanding number of awards at 30 September 2020 was 268,385 and the awards vest over three years from 1 July 2018 subject to certain performance conditions being met. Each original award was fair valued at the date of grant at SEK 167.10 using an option pricing model.

Accounting Policies

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

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

The accounting policies adopted are in all aspects consistent with those followed in the preparation of the Group's annual financial statements for the year ended 31 December 2019.

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

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

Risks and Risk Management

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

A detailed analysis of Lundin Energy's strategic, operational, financial and external risks and mitigation of those risks through risk management is described in Lundin Energy's 2019 Annual Report.

Coronavirus Crisis and Low Oil Price Response

Detailed contingency plans have been established to mitigate the risk, a key element of which is that all personnel visiting the Company's operated production and drilling sites are now tested for the virus before travelling offshore.The Company's main offices are largely back to normal occupancy levels, consistent with authority guidelines and offshore activities are continuing with normal manning levels, which means that some activities previously deferred to manage the risk have been brought forward to optimise longterm business outcomes. To date there have been no disruptions to production due to the coronavirus situation.

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

Buy	Sell	Average contractual Exchange rate	Settlement period
MNOK 4,627.3	MUSD 515.1	NOK 8.98:USD 1	Oct 2020 – Dec 2020
MNOK 3,640.0	MUSD 437.7	NOK 8.32:USD 1	Jan 2021 – Dec 2021
MNOK 1,430.0	MUSD 183.4	NOK 7.80:USD 1	Jan 2022 – Dec 2022
MNOK 530.0	MUSD 64.2	NOK 8.26:USD 1	Jan 2023 – Dec 2023
MNOK 300.0	MUSD 33.0	NOK 9.09:USD 1	Jan 2024 – Dec 2024

Lundin Energy entered into interest rate hedge contracts and at 30 September 2020 had outstanding interest rate hedge contracts as follows:

Borrowings expressed in MUSD	Fixing of floating LIBOR average rate per annum	Settlement period
3,300	1.96%	Oct 2020 – Dec 2020
3,100	2.28%	Jan 2021 – Dec 2021
3,200	2.20%	Jan 2022 – Dec 2022
2,700	1.38%	Jan 2023 – Dec 2023
2,200	1.47%	Jan 2024 – Dec 2024
1,400	0.71%	Jan 2025 – Dec 2025
1,100	0.81%	Jan 2026 – Jun 2026

Under IFRS 9, subject to hedge effectiveness testing, most of the foreign currency contracts and interest rate hedges are treated as effective and changes to the fair value are reflected in other comprehensive income with the changes to the fair value of non effective hedges reflected in the income statement

Exchange Rates

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

		30 Sep 2020		30 Sep 2019		31 Dec 2019
	Average	Period end	Average	Period end	Average	Period end
1 USD equals NOK	9.5450	9.4814	8.6957	9.0874	8.8003	8.7803
1 USD equals Euro	0.8896	0.8541	0.8899	0.9184	0.8932	0.8902
1 USD equals SEK	9.4088	9.0291	9.4060	9.8226	9.4581	9.2993

	Third quarter 2020 Average	Third quarter 2019 Average
1 USD equals NOK	9.1275	8.8634
1 USD equals Euro	0.8551	0.8996
1 USD equals SEK	8.8637	9.5946

Consolidated Income Statement

Expressed in MUSD	Note	1 Jan 2020- 30 Sep 2020 9 months	1 Jul 2020- 30 Sep 2020 3 months	1 Jan 2019- 30 Sep 2019 9 months	1 Jul 2019- 30 Sep 2019 3 months	1 Jan 2019- 31 Dec 2019 12 months
Revenue and other income	1
Revenue		1,759.8	679.2	1,418.3	450.5	2,158.6
Gain from sale of assets		–	–	756.7	756.7	756.7
Other income		24.9	7.8	24.0	7.8	33.4
		1,784.7	687.0	2,199.0	1,215.0	2,948.7

Cost of sales
Production costs	2	-139.2	-35.9	-118.6	-41.6	-164.8
Depletion and decommissioning costs		-446.8	-150.9	-301.6	-105.0	-443.8
Exploration costs		-47.3	-0.6	-84.7	-13.8	-125.6
Impairment costs of oil and gas properties		–	–	–	–	-128.3
Purchase of crude oil from third parties		-193.3	-130.0	-84.3	–	-84.3
Gross profit	3	958.1	369.6	1,609.8	1,054.6	2,001.9
General, administration and depreciation
expenses		-25.5	-7.3	-21.6	-7.1	-31.2
Operating profit		932.6	362.3	1,588.2	1,047.5	1,970.7
Net financial items
Finance income	4	1.0	0.2	23.8	-27.7	27.5
Finance costs	5	-258.2	84.9	-366.6	-288.2	-322.5
		-257.2	85.1	-342.8	-315.9	-295.0
Share in result of joint ventures and associated company		0.0	0.0	-1.3	-0.3	-1.8
Profit before tax		675.4	447.4	1,244.1	731.3	1,673.9
Income tax	6	-594.9	-235.1	-574.5	-211.4	-849.0
Net result		80.5	212.3	669.6	519.9	824.9
Attributable to:
Shareholders of the Parent Company		80.5	212.3	669.6	519.9	824.9
Non-controlling interest		–	–	–	–	–
		80.5	212.3	669.6	519.9	824.9
Earnings per share – USD			0.74		1.72	2.61
Earnings per share fully diluted – USD		0.28	0.74	2.05	1.71	2.61
		0.28		2.05
Adjusted earnings per share – USD		0.68	0.27	0.53	0.15	0.80
Adjusted earnings per share fully diluted – USD		0.68	0.27	0.53	0.15	0.80

Consolidated Statement of Comprehensive Income

Expressed in MUSD	1 Jan 2020- 30 Sep 2020 9 months	1 Jul 2020- 30 Sep 2020 3 months	1 Jan 2019- 30 Sep 2019 9 months	1 Jul 2019- 30 Sep 2019 3 months	1 Jan 2019- 31 Dec 2019 12 months
Net result	80.5	212.3	669.6	519.9	824.9

Items that may be subsequently reclassified to profit or loss:
Exchange differences foreign operations	-146.4	-105.9	74.1	61.5	29.0
Cash flow hedges	-178.5	78.4	-172.1	-102.5	-82.5
Other comprehensive income, net of tax	-324.9	-27.5	-98.0	-41.0	-53.5

Total comprehensive income	-244.4	184.8	571.6	478.9	771.4

Attributable to:
Shareholders of the Parent Company	-244.4	184.8	571.6	478.9	771.4
Non-controlling interest	–	–	–	–	–
	-244.4	184.8	571.6	478.9	771.4

Consolidated Balance Sheet

Expressed in MUSD	Note	30 September 2020	31 December 2019
ASSETS
Non-current assets
Oil and gas properties	7	5,180.1	5,473.2
Other tangible fixed assets	8	42.0	49.4
Goodwill		128.1	128.1
Investments in joint ventures		84.3	–
Financial assets	9	13.4	14.3
Trade and other receivables	10	15.5	–
Derivative instruments	14	–	2.7
Total non-current assets		5,463.4	5,667.7

Current assets
Inventories		42.1	40.7
Trade and other receivables	10	289.0	349.5
Derivative instruments	14	–	11.3
Cash and cash equivalents		129.2	85.3
Total current assets		460.3	486.8

TOTAL ASSETS		5,923.7	6,154.5
EQUITY AND LIABILITIES
Equity
Shareholders´ equity		-2,125.6	-1,598.8
Liabilities
Non-current liabilities
Financial liabilities	11	3,180.7	3,888.4
Provisions	12	500.3	528.1
Deferred tax liabilities		2,571.5	2,412.7
Derivative instruments	14	200.4	110.8
Total non-current liabilities		6,452.9	6,940.0
Current liabilities
Financial liabilities	11	591.0	97.5
Dividends		142.9	106.0
Trade and other payables	13	240.7	177.4
Derivative instruments	14	123.2	33.2
Current tax liabilities		479.0	343.3
Provisions	12	19.6	55.9
Total current liabilities		1,596.4	813.3

Total liabilities		8,049.3	7,753.3
TOTAL EQUITY AND LIABILITIES		5,923.7	6,154.5

Consolidated Statement of Cash Flows

Expressed in MUSD	1 Jan 2020- 30 Sep 2020 9 months	1 Jul 2020- 30 Sep 2020 3 months	1 Jan 2019- 30 Sep 2019 9 months	1 Jul 2019- 30 Sep 2019 3 months	1 Jan 2019- 31 Dec 2019 12 months
Cash flows from operating activities
Net result	80.5	212.3	669.6	519.9	824.9
Adjustments for:
Gain from sale of assets	–	–	-756.7	-756.7	-756.7
Exploration costs	47.3	0.6	84.7	13.8	125.6
Depletion, depreciation and amortisation Impairment of oil and gas properties	452.0 –	152.8 –	306.6 –	106.6 –	450.5 128.3
Current tax	251.2	121.7	80.5	36.7	405.8
Deferred tax	343.7	113.4	494.0	174.7	443.2
Long-term incentive plans	5.4	1.8	10.1	3.4	14.7
Foreign currency exchange gain/ loss	30.3	-154.6	191.3	234.9	70.8
Interest expense	77.9	19.8	54.7	22.8	93.4
Unwinding of loan modification gain	29.1	10.1	31.4	10.3	41.5
Amortisation of deferred financing fees	12.3	4.4	15.8	7.4	19.7
Other	12.8	4.6	13.4	4.2	17.8

Interest received	0.6	0.1	1.3	0.5	1.8
Interest paid	-93.3	-25.6	-118.2	-35.0	-177.4
Income taxes paid / received	-90.9	-37.8	-35.4	-19.6	-132.7
Changes in working capital	92.4	-70.4	-57.8	-93.1	-193.0
Total cash flows from operating activities	1,251.3	353.2	985.3	230.8	1,378.2
Cash flows from investing activities
Investment in oil and gas properties	-579.2	-160.8	-821.9	-237.6	-1,057.8
Investment in renewable energy business1	-80.8	-3.8	–	–	-1.2
Investment in other fixed assets	-1.6	-0.3	-1.4	-0.5	-2.5
Investment in financial assets	–	–	-0.3	-0.3	-0.3
Disposal of fixed assets2	–	–	959.0	959.0	959.0
Decommissioning costs paid	-44.0	-24.1	-2.8	-0.9	-3.7
Total cash flows from investing activities	-705.6	-189.0	132.6	719.7	-106.5
Cash flows from financing activities
Changes in long-term bank loans3	-256.0	-35.0	685.0	690.0	627.0
Repayment of principal portion of lease commitments	-2.4	-0.9	-2.6	-0.8	-3.4
Financing fees paid	-2.5	–	-3.3	-3.3	-3.3

Dividends paid	-247.1	-71.0	-250.5	-125.3	-355.6
Share redemption	–	–	-1,517.2	-1,517.2	-1,517.2
Total cash flows from financing activities	-508.0	-106.9	-1,088.6	-956.6	-1,252.5
Change in cash and cash equivalents Cash and cash equivalents at the beginning	37.7	57.3	29.3	-6.1	19.2
of the period Currency exchange difference in cash and	85.3	74.9	66.8	100.7	66.8
cash equivalents	6.2	-3.0	-1.0	0.5	-0.7
Cash and cash equivalents at the end of the period	129.2	129.2	95.1	95.1	85.3

1 Includes incurred cost relating to the acquisition of the renewable energy business

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

3 Includes drawings during the reporting period of MUSD 86.0 under the credit facility for the financing of the renewable power projects

Consolidated Statement of Changes in Equity

		Additional paid-in capital/Other	Retained
Expressed in MUSD	Share capital	reserves	earnings	Dividends	Total equity
At 1 January 2019	0.5	-178.6	-205.7	–	-383.8
Reclassification currency translation reserves	–	76.1	-76.1	–	–
Restated equity at 1 January 2019	0.5	-102.5	-281.8	–	-383.8
Comprehensive income
Net result	–	–	669.6	–	669.6
Other comprehensive income	–	-98.0	–	–	-98.0
Total comprehensive income	–	-98.0	669.6	–	571.6
Transactions with owners
Distributions	–	–	–	-501.0	-501.0
Share redemption	-0.1	–	-1,476.9	–	-1,477.0
Bonus issue (sw. fondemission)	0.1	–	-0.1	–	–
Share based payments	–	-13.7	–	–	-13.7
Value of employee services	–	–	4.0	–	4.0
Total transaction with owners	–	-13.7	-1,473.0	-501.0	-1,987.7
At 30 September 2019	0.5	-214.2	-1,085.2	-501.0	-1,799.9
Comprehensive income
Net result	–	–	155.3	–	155.3
Other comprehensive income	–	44.5	–	–	44.5
Total comprehensive income	–	44.5	155.3	–	199.8
Transactions with owners
Value of employee services	–	–	1.3	–	1.3
Total transaction with owners	–	–	1.3	–	1.3
At 31 December 2019	0.5	-169.7	-928.6	-501.0	-1,598.8
Transfer of prior year dividends	–	–	-501.0	501.0	–
Comprehensive income
Net result	–	–	80.5	–	80.5
Other comprehensive income Total comprehensive income	– –	-324.9 -324.9	– 80.5	– –	-324.9 -244.4
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	–	–	4.0	–	4.0
Total transaction with owners	–	-2.3	4.0	-284.1	-282.4
At 30 September 2020	0.5	-496.9	-1,345.1	-284.1	-2,125.6

	1 Jan 2020-	1 Jul 2020-	1 Jan 2019-	1 Jul 2019-	1 Jan 2019-
Note 1 – Revenue and other income	30 Sep 2020	30 Sep 2020	30 Sep 2019	30 Sep 2019	31 Dec 2019
MUSD	9 months	3 months	9 months	3 months	12 months
Revenue
Crude oil from own production	1,478.0	516.3	1,243.0	431.7	1,939.8
Crude oil from third party activities	196.6	132.8	84.3	–	84.3
Condensate	40.2	15.2	23.6	0.2	41.4
Gas	45.0	14.9	67.4	18.6	93.1
Sales of oil and gas	1,759.8	679.2	1,418.3	450.5	2,158.6

Gain from sale of assets	–	–	756.7	756.7	756.7
Other income	24.9	7.8	24.0	7.8	33.4
Revenue and other income	1,784.7	687.0	2,199.0	1,215.0	2,948.7

Note 2 – Production costs MUSD	1 Jan 2020- 30 Sep 2020 9 months	1 Jul 2020- 30 Sep 2020 3 months	1 Jan 2019- 30 Sep 2019 9 months	1 Jul 2019- 30 Sep 2019 3 months	1 Jan 2019- 31 Dec 2019 12 months
Cost of operations	101.9	32.4	81.9	25.5	118.1
Tariff and transportation expenses	36.4	13.5	30.7	10.9	46.3
Change in under/over lift position	-3.9	-12.0	2.6	4.2	-0.9
Change in inventory position	0.4	0.5	0.3	–	-2.8
Other	4.4	1.5	3.1	1.0	4.1
Production costs	139.2	35.9	118.6	41.6	164.8

Note 3 – Segment information MUSD	1 Jan 2020- 30 Sep 2020	1 Jul 2020- 30 Sep 2020	1 Jan 2019- 30 Sep 2019	1 Jul 2019- 30 Sep 2019	1 Jan 2019- 31 Dec 2019
Norway	9 months	3 months	9 months	3 months	12 months
Crude oil from own production	1,478.0	516.3	1,243.0	431.7	1,939.8
Condensate	40.2	15.2	23.6	0.2	41.4
Gas	45.0	14.9	67.4	18.6	93.1
Revenue	1,563.2	546.4	1,334.0	450.5	2,074.3
Gain from sale of assets	–	–	756.7	756.7	756.7
Other income	24.0	7.7	24.0	7.8	33.4
Revenue and other income	1,587.2	554.1	2,114.7	1,215.0	2,864.4
Production costs	-139.2	-35.9	-118.6	-41.6	-164.8
Depletion and decommissioning costs	-446.8	-150.9	-301.6	-105.0	-443.8
Exploration costs	-47.3	-0.6	-84.7	-13.8	-125.6
Impairment costs of oil and gas properties	–	–	–	–	-128.3
Gross profit	953.9	366.7	1,609.8	1,054.6	2,001.9

Other
Crude oil from third party activities	196.6	132.8	84.3	–	84.3
Revenue	196.6	132.8	84.3	–	84.3
Other income	0.9	0.1	–	–	–
Revenue and other income	197.5	132.9	84.3	–	84.3
Purchase of crude oil from third parties	-193.3	-130.0	-84.3	–	-84.3
Gross profit	4.2	2.9	0.0	–	0.0

	1 Jan 2020-	1 Jul 2020-	1 Jan 2019-	1 Jul 2019-	1 Jan 2019-
Note 3 – Segment information cont.	30 Sep 2020	30 Sep 2020	30 Sep 2019	30 Sep 2019	31 Dec 2019
MUSD	9 months	3 months	9 months	3 months	12 months
Total
Crude oil from own production	1,478.0	516.3	1,243.0	431.7	1,939.8
Crude oil from third party activities	196.6	132.8	84.3	–	84.3
Condensate	40.2	15.2	23.6	0.2	41.4
Gas	45.0	14.9	67.4	18.6	93.1
Revenue	1,759.8	679.2	1,418.3	450.5	2,158.6
Gain from sale of assets	–	–	756.7	756.7	756.7
Other income	24.9	7.8	24.0	7.8	33.4
Revenue and other income	1,784.7	687.0	2,199.0	1,215.0	2,948.7
Production costs	-139.2	-35.9	-118.6	-41.6	-164.8
Depletion and decommissioning costs	-446.8	-150.9	-301.6	-105.0	-443.8
Exploration costs	-47.3	-0.6	-84.7	-13.8	-125.6
Impairment costs of oil and gas properties	–	–	–	–	-128.3
Purchase of crude oil from third parties	-193.3	-130.0	-84.3	–	-84.3
Gross profit	958.1	369.6	1,609.8	1,054.6	2,001.9

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

Note 4 – Finance income MUSD	1 Jan 2020- 30 Sep 2020 9 months	1 Jul 2020- 30 Sep 2020 3 months	1 Jan 2019- 30 Sep 2019 9 months	1 Jul 2019- 30 Sep 2019 3 months	1 Jan 2019- 31 Dec 2019 12 months
Foreign currency exchange gain, net	–	–	–	-34.7	–
Interest income	1.0	0.2	1.3	0.5	1.8
Gain on interest rate hedge settlement	–	–	22.5	6.5	25.7
Finance income	1.0	0.2	23.8	-27.7	27.5

Note 5 – Finance costs MUSD	1 Jan 2020- 30 Sep 2020 9 months	1 Jul 2020- 30 Sep 2020 3 months	1 Jan 2019- 30 Sep 2019 9 months	1 Jul 2019- 30 Sep 2019 3 months	1 Jan 2019- 31 Dec 2019 12 months
Foreign currency exchange loss, net	85.2	-142.6	237.7	237.7	131.7
Interest expense	77.9	19.8	54.7	22.8	93.4
Loss on interest rate hedge settlement	29.3	14.9	–	–	–
Unwinding of site restoration discount	14.1	4.9	13.4	4.4	17.9
Amortisation of deferred financing fees	12.3	4.4	15.8	7.4	19.7
Loan facility commitment fees	8.7	3.0	8.9	1.9	10.9
Unwinding of loan modification gain	29.1	10.1	31.4	10.3	41.5
Other	1.6	0.6	4.7	3.7	7.4
Finance costs	258.2	-84.9	366.6	288.2	322.5

Note 6 – Income tax	1 Jan 2020- 30 Sep 2020	1 Jul 2020- 30 Sep 2020	1 Jan 2019- 30 Sep 2019	1 Jul 2019- 30 Sep 2019	1 Jan 2019- 31 Dec 2019
MUSD	9 months	3 months	9 months	3 months	12 months
Current tax	251.2	121.7	80.5	36.7	405.8
Deferred tax	343.7	113.4	494.0	174.7	443.2
Income tax	594.9	235.1	574.5	211.4	849.0

Note 7 – Oil and gas properties MUSD	30 September 2020	31 December 2019
Norway
Producing assets	3,491.9	4,065.3
Assets under development	995.0	652.2
Capitalised exploration and appraisal expenditure	693.2	755.7
	5,180.1	5,473.2

Note 8 – Other tangible fixed assets MUSD	30 September 2020	31 December 2019
Right of use assets	29.0	35.9
Other	13.0	13.5
	42.0	49.4

Note 9 – Financial assets MUSD	30 September 2020	31 December 2019
Contingent consideration	12.6	12.4
Associated companies	0.3	0.3
Other	0.5	1.6
	13.4	14.3

Note 10 – Trade and other receivables
MUSD	30 September 2020	31 December 2019
Non-current:
Prepaid expenses and accrued income	15.5	–
	15.5	–
Current:
Trade receivables	231.8	305.1
Underlift	11.0	2.0
Joint operations debtors	12.9	11.4
Prepaid expenses and accrued income	27.0	23.9
Other	6.3	7.1
	289.0	349.5

	304.5	349.5

Note 11 – Financial liabilities
---------------------------------	--	--

MUSD	30 September 2020	31 December 2019
Non-current:
Bank loans	3,250.0	4,000.0
Capitalised financing fees	-24.5	-37.1
Capitalised loan modification gain	-69.8	-105.6
Lease commitments	25.0	31.1
	3,180.7	3,888.4
Current:
Bank loans	586.0	92.0
Lease commitments	5.0	5.5
	591.0	97.5

	3,771.7	3,985.9

Note 12 – Provisions
MUSD	30 September 2020	31 December 2019
Non-current:
Site restoration	496.5	522.2
Long-term incentive plans	1.2	2.7
Other	2.6	3.2
	500.3	528.1
Current:
Site restoration	16.6	49.2
Long-term incentive plans	3.0	6.7
	19.6	55.9

	519.9	584.0

Note 13 – Trade and other payables

MUSD	30 September 2020	31 December 2019
Trade payables	83.2	17.8
Overlift	6.7	0.9
Joint operations creditors and accrued expenses	119.4	133.6
Other accrued expenses	28.3	16.6
Other	3.1	8.5
	240.7	177.4

Note 14 – Financial instruments

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

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

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

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

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

30 September 2020
MUSD	Level 1	Level 2	Level 3
Assets
Contingent consideration	–	–	12.6
Derivative instruments – non-current	–	–	–
Derivative instruments – current	–	–	–
	–	–	12.6
Liabilities
Derivative instruments – non-current	–	200.4	–
Derivative instruments – current	–	123.2	–
	–	323.6	–

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

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

The fair value of the financial assets is estimated to equal the carrying value. The fair value of the derivative instruments is calculated using the forward interest rate curve and the forward exchange rate curve respectively for the interest rate swap and the currency hedging contracts. The hedge counterparties are all banks which are party to the loan facility agreement. The sale of 2.6 percent of Johan Sverdrup during 2019 included a contingent consideration based on future reserve reclassifications and is due in 2026, This contingent consideration was fair valued by the Company in 2019 with no changes in 2020.

Note 15 – Additional disclosures

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

Parent Company Income Statement

	1 Jan 2020-	1 Jul 2020-	1 Jan 2019-	1 Jul 2019-	1 Jan 2019-
	30 Sep 2020	30 Sep 2020	30 Sep 2019	30 Sep 2019	31 Dec 2019
Expressed in MSEK	9 months	3 months	9 months	3 months	12 months
Revenue	12.3	0.7	9.5	1.0	18.9

General and administration expenses	-175.7	-56.4	-170.5	-83.9	-248.1
Operating loss	-163.4	-55.7	-161.0	-82.9	-229.2

Net financial items
Finance income	2,867.8	–	19,159.8	14,520.8	19,148.5
Finance costs	-4.1	-2.8	-33.2	-33.1	-33.8
	2,863.7	-2.8	19,126.6	14,487.7	19,114.7

Profit before tax	2,700.3	-58.5	18,965.6	14,404.8	18,885.5

Income tax	–	–	–	–	–

Net result	2,700.3	-58.5	18,965.6	14,404.8	18,885.5

Parent Company Comprehensive Income Statement

Expressed in MSEK	1 Jan 2020- 30 Sep 2020 9 months	1 Jul 2020- 30 Sep 2020 3 months	1 Jan 2019- 30 Sep 2019 9 months	1 Jul 2019- 30 Sep 2019 3 months	1 Jan 2019- 31 Dec 2019 12 months
Net result	2,700.3	-58.5	18,965.6	14,404.8	18,885.5
Other comprehensive income	–	–	–	–	–
Total comprehensive income	2,700.3	-58.5	18,965.6	14,404.8	18,885.5
Attributable to:
Shareholders of the Parent Company	2,700.3	-58.5	18,965.6	14,404.8	18,885.5
	2,700.3	-58.5	18,965.6	14,404.8	18,885.5

Parent Company Balance Sheet

Expressed in MSEK	30 September 2020	31 December 2019
ASSETS
Non-current assets
Shares in subsidiaries	55,118.9	55,118.9
Other tangible fixed assets	0.5	0.4
Total non-current assets	55,119.4	55,119.3

Current assets
Receivables	1,316.1	1,107.4
Cash and cash equivalents	32.1	31.7
Total current assets	1,348.2	1,139.1

TOTAL ASSETS	56,467.6	56,258.4

SHAREHOLDERS´EQUITY AND LIABILITIES
Shareholders´ equity including net result for the period	55,138.4	55,242.8

Non-current liabilities
Provisions	0.6	1.0
Total non-current liabilities	0.6	1.0

Current liabilities
Dividends	1,290.2	985.7
Other liabilities	38.4	28.9
Total current liabilities	1,328.6	1,014.6

Total liabilities	1,329.2	1,015.6

TOTAL EQUITY AND LIABILITIES	56,467.6	56,258.4

Parent Company Cash Flow Statement

Expressed in MSEK	1 Jan 2020- 30 Sep 2020 9 months	1 Jul 2020- 30 Sep 2020 3 months	1 Jan 2019- 30 Sep 2019 9 months	1 Jul 2019- 30 Sep 2019 3 months	1 Jan 2019- 31 Dec 2019 12 months
Cash flow from operations
Net result	2,700.3	-58.5	18,965.6	14,404.8	18,885.5
Adjustment for non-cash related items	-1,429.6	719.8	-2,329.4	1,149.4	-1,157.9
Changes in working capital	1,022.8	-61.5	201.3	121.9	133.0
Total cash flow from operations	2,293.5	599.8	16,837.5	15,676.1	17,860.6
Cash flow from investing
Investments in other fixed assets	-0.2	–	-0.1	-0.1	-0.1
Total cash flow from investing	-0.2	–	-0.1	-0.1	-0.1
Cash flow from financing
Dividends paid	-2,354.8	-661.9	-2,322.2	-1,161.1	-3,347.6
Issuance of treasury shares	63.1	63.1	–	–	–
Share redemption	–	–	-14,510.3	-14,510.3	-14,510.3
Total cash flow from financing	-2,291.7	-598.8	-16,832.5	-16,832.5	-17,857.9
Change in cash and cash equivalents	1.6	1.0	4.9	4.6	2.6
Cash and cash equivalents at the beginning of the period	31.7	32.3	29.5	30.6	29.5
Currency exchange difference in cash and cash equivalents	-1.2	-1.2	2.5	1.7	-0.4
Cash and cash equivalents at the end of the period	32.1	32.1	36.9	36.9	31.7

Parent Company Statement of Changes in Equity

		Restricted equity		Unrestricted equity
Expressed in MSEK	Share capital	Statutory reserve	Other reserves	Retained earnings	Dividends	Total	Total equity
Balance at 1 January 2019	3.5	861.3	6,479.7	47,776.3	–	54,256.0	55,120.8
Total comprehensive income	–	–	–	18,965.6	–	18,965.6	18,965.6
Transactions with owners
Distributions	–	–	–	–	-4,638.7	-4,638.7	-4,638.7
Share redemption	-0.6	–	–	-14,124.2	–	-14,124.2	-14,124.8
Bonus issue (sw. fondemission)	0.6	–	–	-0.6	–	-0.6	–
Total transactions with owners	–	–	–	-14,124.8		-4,638.7 -18,763.5	-18,763.5
Balance at 30 September 2019	3.5	861.3	6,479.7	52,617.1	-4,638.7	54,458.1	55,322.9
Total comprehensive income	–	–	–	-80.1	–	-80.1	-80.1
Balance at 31 December 2019	3.5	861.3	6,479.7	52,537.0	-4,638.7	54,378.0	55,242.8
Transfer of prior year dividends	–	–	–	-4,638.7	4,638.7	–	–
Total comprehensive income	–	–	–	2,700.3	–	2,700.3	2,700.3
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 30 September 2020	3.5	861.3	6,542.8	50,598.6	-2,867.8	54,273.6	55,138.4

Key Financial Data

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

Financial data MUSD	1 Jan 2020- 30 Sep 2020 9 months	1 Jul 2020- 30 Sep 2020 3 months	1 Jan 2019- 30 Sep 2019 9 months	1 Jul 2019- 30 Sep 2019 3 months	1 Jan 2019- 31 Dec 2019 12 months
Revenue and other income	1,784.7	687.0	2,199.0	1,215.0	2,948.7
Operating cash flow1	1,201.0	399.4	1,158.9	380.0	1,537.1
CFFO	1,251.3	353.2	985.3	230.8	1,378.2
EBITDA1	1,431.8	515.6	1,222.9	411.3	1,918.4
Free cash flow	545.7	164.2	1,117.9	950.5	1,271.7
Net result	80.5	212.3	669.6	519.9	824.9
Adjusted net result	193.1	75.8	173.8	45.4	252.7
Net debt	3,706.8	3,706.8	4,054.9	4,054.9	4,006.7
Data per share USD
Shareholders' equity per share	-7.48	-7.48	-6.34	-6.34	-5.63
Operating cash flow per share1	4.23	1.40	3.55	1.25	4.87
CFFO per share	4.40	1.24	3.16	0.91	4.36
EBITDA per share1	5.04	1.81	3.75	1.36	6.07
Free cash flow per share	1.92	0.58	3.42	2.91	4.03
Earnings per share	0.28	0.74	2.05	1.72	2.61
Earnings per share fully diluted	0.28	0.74	2.05	1.71	2.61
Adjusted earnings per share	0.68	0.27	0.53	0.15	0.80
Adjusted earnings per share fully diluted	0.68	0.27	0.53	0.15	0.80
Dividend per share2	0.87	0.25	0.74	0.74	1.11
Number of shares issued at period end	285,924,614	285,924,614	285,924,614	285,924,614	285,924,614
Number of shares in circulation at period end	284,351,471	284,351,471	284,051,304	284,051,304	284,051,304
Weighted average number of shares for the period	284,119,225	284,253,590	326,543,502	302,994,550	315,833,140
Weighted average number of shares for the period fully diluted	284,758,504	284,736,009	327,263,582	303,534,682	316,551,300
Share price
Share price at period end in SEK	178.50	178.50	295.30	295.30	318.30
Share price at period end in USD3	19.77	19.77	30.06	30.06	34.23
Key ratios
Return on equity (%)4	–	–	–	–	–
Return on capital employed (%)	18	7	28	19	35
Net debt/equity ratio (%)4	–	–	–	–	–
Net debt/EBITDA ratio1	1.7	1.7	2.4	2.4	2.1
Equity ratio (%)	-36	-36	-31	-31	-26
Share of risk capital (%)	8	8	10	10	13
Interest coverage ratio	8	10	28	45	20
Operating cash flow/interest ratio1	11	12	21	17	16
Yield	4	1	2	1	3

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

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

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

4 As the equity at 30 September 2020, 31 December 2019 and 30 September 2019 is negative, these ratios have not been calculated.

Relevant Reconciliations of Alternative Performance Measures

EBITDA MUSD	1 Jan 2020- 30 Sep 2020 9 months	1 Jul 2020- 30 Sep 2020 3 months	1 Jan 2019- 30 Sep 2019 9 months	1 Jul 2019- 30 Sep 2019 3 months	1 Jan 2019- 31 Dec 2019 12 months
Operating profit	932.6	362.3	1,588.2	1,047.5	1,970.7
Minus: gain from sale of assets	–	–	-756.7	-756.7	-756.7
Add: depletion of oil and gas properties	446.8	150.9	301.6	105.0	443.8
Add: exploration costs	47.3	0.6	84.7	13.8	125.6
Add: impairment costs of oil and gas properties	–	–	–	–	128.3
Add: depreciation of other tangible assets	5.1	1.8	5.1	1.7	6.7
EBITDA	1,431.8	515.6	1,222.9	411.3	1,918.4

Operating cash flow MUSD	1 Jan 2020- 30 Sep 2020 9 months	1 Jul 2020- 30 Sep 2020 3 months	1 Jan 2019- 30 Sep 2019 9 months	1 Jul 2019- 30 Sep 2019 3 months	1 Jan 2019- 31 Dec 2019 12 months
Revenue and other income	1,784.7	687.0	2,199.0	1,215.0	2,948.7
Minus: gain from sale of assets	–	–	-756.7	-756.7	-756.7
Minus: production costs	-139.2	-35.9	-118.6	-41.6	-164.8
Minus: purchase of crude oil from third parties	-193.3	-130.0	-84.3	–	-84.3
Minus: current taxes	-251.2	-121.7	-80.5	-36.7	-405.8
Operating cash flow	1,201.0	399.4	1,158.9	380.0	1,537.1

Free cash flow MUSD	1 Jan 2020- 30 Sep 2020 9 months	1 Jul 2020- 30 Sep 2020 3 months	1 Jan 2019- 30 Sep 2019 9 months	1 Jul 2019- 30 Sep 2019 3 months	1 Jan 2019- 31 Dec 2019 12 months
Cash flows from operating activities (CFFO)	1,251.3	353.2	985.3	230.8	1,378.2
Minus: cash flows from investing activities	-705.6	-189.0	132.6	719.7	-106.5
Free cash flow	545.7	164.2	1,117.9	950.5	1,271.7

Adjusted net result MUSD	1 Jan 2020- 30 Sep 2020 9 months	1 Jul 2020- 30 Sep 2020 3 months	1 Jan 2019- 30 Sep 2019 9 months	1 Jul 2019- 30 Sep 2019 3 months	1 Jan 2019- 31 Dec 2019 12 months
Net result	80.5	212.3	669.6	519.9	824.9
Adjusted for gain or loss from sale of assets	–	–	-756.7	-756.7	-756.7
Adjusted for impairment costs of oil and gas properties	–	–	–	–	128.3
Adjusted for unwinding of loan modification gain	29.1	10.1	31.4	10.3	41.5
Adjusted for foreign currency exchange gain or loss	85.2	-142.6	237.7	272.4	131.7
Adjusted for tax effects of above mentioned items	-1.7	-4.0	-8.2	-0.5	-117.0
Adjusted net result	193.1	75.8	173.8	45.4	252.7

Net debt	1 Jan 2020- 30 Sep 2020	1 Jul 2020- 30 Sep 2020	1 Jan 2019- 30 Sep 2019	1 Jul 2019- 30 Sep 2019	1 Jan 2019- 31 Dec 2019
MUSD	9 months	3 months	9 months	3 months	12 months
Bank loans	3,836.0	3,836.0	4,150.0	4,150.0	4,092.0
Minus: cash and cash equivalents	-129.2	-129.2	-95.1	-95.1	-85.3
Net debt	3,706.8	3,706.8	4,054.9	4,054.9	4,006.7

Key Ratio Definitions

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Net debt: Bank loan less cash and cash equivalents.

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

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

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

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

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

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

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

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

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

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

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

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

Financial Information

The Company will publish the following reports:

The year end report (January December 2020) will be published on 28 January 2021.
The three month report (January March 2021) will be published on 29 April 2021.
The six month report (January June 2021) will be published on 28 July 2021.

The AGM will be held on 30 March 2021 in Stockholm, Sweden.

For further information, please contact:

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

Edward Westropp Robert Eriksson Head of Media Communications Tel: +46 701 11 26 15

Definitions and abbreviations

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

EBITDA	Earnings Before Interest, Tax, Depreciation and Amortisation
CHF	Swiss franc
EUR	Euro
NOK	Norwegian Krone
SEK	Swedish Krona
USD	US dollar
TSEK	Thousand SEK
TUSD	Thousand USD
MSEK	Million SEK
MUSD	Million USD

Oil related terms and measurements

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

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 forwardlooking 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 Wlundin-energy.com

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Orrön Energy

2942_10-q_2020-10-30_87809f8e-fb48-451c-820b-81ce24738567.pdf

Q Report for the NINE MONTHS ended 30 September 2020 3

Highlights

Financial summary

Comment from Alex Schneiter, President and CEO of Lundin Energy:

Highlights

OPERATIONAL REVIEW

Coronavirus Crisis and Low Oil Price Response

Guidance Update

Production

Development

Johan Sverdrup Phase 2

Greater Edvard Grieg Area Tie-Back Projects

Appraisal

2020 appraisal well programme

Exploration

2020 exploration well programme

Decarbonisation Strategy and Renewable Energy Projects

Decommissioning

Licence Awards and Transactions

Health, Safety and Environment

FINANCIAL REVIEW

Result

Norwegian tax changes

Changes in the Group

Revenue and other income

Production costs

Depletion and decommissioning costs

Exploration costs

Purchase of crude oil from third parties

General, administrative and depreciation expenses

Finance income

Finance costs

Share in result of joint ventures and associated company

Tax

Balance Sheet

Non-current assets

Current assets

Non-current liabilities

Current liabilities

Parent Company

Related Party Transactions

Liquidity

Contingent liabilities

Subsequent Events

Share Data

Remuneration

Unit Bonus Plan

Performance Based Incentive Plan

Accounting Policies

Risks and Risk Management

Coronavirus Crisis and Low Oil Price Response

Derivative financial instruments

Exchange Rates

Consolidated Income Statement

Consolidated Statement of Comprehensive Income

Consolidated Balance Sheet

Consolidated Statement of Cash Flows

Consolidated Statement of Changes in Equity

Note 13 – Trade and other payables

Note 14 – Financial instruments

Note 15 – Additional disclosures

Parent Company Income Statement

Parent Company Comprehensive Income Statement

Parent Company Balance Sheet

Parent Company Cash Flow Statement

Parent Company Statement of Changes in Equity

Key Financial Data

Relevant Reconciliations of Alternative Performance Measures

Key Ratio Definitions

Financial Information

The Company will publish the following reports:

Definitions and abbreviations

Oil related terms and measurements

Forward-Looking Statements

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