Orrön Energy

Quarterly Report • May 2, 2019

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

Highlights

• Strong production performance of 78.8 Mboepd, at the upper end of the guidance range for the quarter
• Robust EBITDA and free cash flow generation
• Operating cost below forecast at USD 4.51 per barrel for the quarter and full year guidance remains at USD 4.25 per barrel
• Offshore installation of Johan Sverdrup Phase 1 completed, project firmly on schedule for expected first oil in November 2019
• New projects Solveig Phase 1, Rolvsnes Extended Well Test and Frosk test production sanctioned and Edvard Grieg infill drilling committed
• 2019 exploration programme expanded to 17 wells from 15
• Dividend of USD 500 million for the financial year 2018 approved by the 2019 AGM

Financial summary

	1 Jan 2019- 31 Mar 2019 3 months	1 Jan 2018- 31 Mar 2018 3 months	1 Jan 2018- 31 Dec 2018 12 months
Production in Mboepd	78.8	83.1	81.1
Revenue and other income in MUSD	491.6	692.9	2,617.4
Operating cash flow in MUSD	385.0	461.8	1,847.8
EBITDA in MUSD	406.0	456.5	1,916.2
Free cash flow in MUSD	95.8	171.8	663.0
Net result in MUSD	54.9	228.8	222.1
Earnings/share in USD	0.16	0.68	0.66
Net debt	3,303.7	3,724.4	3,398.2

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

"I am pleased to announce another strong quarterly performance across the business. Our Edvard Grieg and Alvheim fields have yet again delivered excellent production efficiency, along with a strong HSE track record, which has driven our production for the quarter to the upper end of expectations, whilst also maintaining our industry leading low operating costs. Also, the trend of industry leading low carbon operations continued at the Edvard Grieg field, coming in at a quarter of the world average.

"At Johan Sverdrup, a significant milestone has been reached with the offshore installation of all the topsides and bridges completed at the end of March, meaning commissioning and hook up has begun in earnest, alongside the tie-back of the eight pre-drilled production wells. With the majority of commissioning for these facilities having taken place onshore and the ability to perform single lift installation using the Pioneering Spirit vessel, I am confident in the expected November 2019 start-up of this world class asset.

"At our Capital Markets Day in January, I outlined the seven potential projects which we have in the pipeline and I am pleased to say that four of these are now underway. With the sanction of the Solveig Phase 1 development and Rolvsnes well test, as well as the commitment to the infill well programme on Edvard Grieg; the production plateau profile at the Greater Edvard Grieg Area will be extended further and this is a clear example of how an organic growth strategy can sustainably deliver significant value creation.

"During the quarter we also added a further two wells to the 2019 exploration programme, bringing the total to 17 wells, our busiest ever. The year has started well in this respect with success at the Froskelår Main well near Alvheim and the remaining programme is targeting net unrisked resources of over 400 MMboe, which ensures a significant, continuous exploration programme throughout the year.

"We have had a strong start to the year and with the completion of the installation of the Johan Sverdrup topsides, the continuing, high impact exploration programme, strong production with industry leading low operating costs and excellent HSE track record; I remain confident in Lundin Petroleum's ability to continue to realise financial and organic growth."

Lundin Petroleum is one of Europe's leading independent oil and gas exploration and production companies with operations focused on Norway and listed on NASDAQ Stockholm (ticker "LUPE"). Read more about Lundin Petroleum's business and operations at www.lundin-petroleum.com

OPERATIONAL REVIEW

All the reported numbers and updates in the operational review relate to the three month period ending 31 March 2019 (reporting period) unless otherwise specified.

Norway

Production

Production was 78.8 thousand barrels of oil equivalent per day (Mboepd) which was 3 percent above mid-point of the production guidance for the quarter and towards the upper end of the guidance range. This result is due to facilities and reservoir performance at the Edvard Grieg field. Production guidance for the full year remains between 75 and 95 Mboepd, reflecting a range around the expected start-up of the Johan Sverdrup field in November 2019.

Operating cost, including netting off tariff income, was USD 4.51 per barrel, which is 5 percent below guidance for the quarter. Full year operating cost guidance remains USD 4.25 per barrel.

Production in Mboepd		1 Jan 2019- 31 Mar 2019 3 months	1 Jan 2018- 31 Mar 2018 3 months	1 Jan 2018- 31 Dec 2018 12 months
Norway
Crude oil		70.1	73.6	71.9
Gas		8.7	9.5	9.2
Total production		78.8	83.1	81.1
Production in Mboepd	WI1	1 Jan 2019- 31 Mar 2019 3 months	1 Jan 2018- 31 Mar 2018 3 months	1 Jan 2018- 31 Dec 2018 12 months
Edvard Grieg	65%	63.3	63.9	63.6
Ivar Aasen	1.385%	0.9	0.9	0.9
Alvheim	15%	10.0	8.9	9.3
Volund	35%	4.2	8.2	6.5
Bøyla	15%	0.4	1.0	0.7
Brynhild	51%	–	0.1	–
Gaupe	40%	–	0.1	0.1
		78.8	83.1	81.1

1 Lundin Petroleum's working interest (WI).

Production from the Edvard Grieg field was above forecast, supported by strong production efficiency ahead of guidance at 99 percent. Reservoir performance continues to exceed expectations; with limited water production and total well potential significantly higher than available facilities capacity. An infill drilling programme is planned at the Edvard Grieg field commencing in 2020, which is targeting 16 MMboe of gross contingent resources based on a three well programme. The Rowan Viking jack-up rig, used to drill all the existing development wells at the Edvard Grieg field, has been contracted for the infill programme on the basis of three firm well slots plus a number of optional slots. Operating cost for the Edvard Grieg field, including netting off tariff income, was USD 4.41 per barrel.

Production from the Ivar Aasen field was in line with forecast. During April 2019, the drilling of two infill production wells commenced and are expected to come on stream in the third quarter of 2019.

Production from the Alvheim area, consisting of the Alvheim, Volund and the Bøyla fields, was in line with forecast. Production efficiency for the Alvheim FPSO was ahead of expectations at 97 percent. During April 2019, the drilling of a sidetrack infill production well was completed at the Volund field and is expected to come on stream in the second quarter 2019. The Frosk test production well is currently drilling and is expected to come on stream in the third quarter of 2019. The Frosk well will be produced through the Bøyla facilities and is planned as a two branch producer also including two pilot holes, one of which is targeting the Froskelår North East prospect. Operating cost for the Alvheim area was USD 5.79 per barrel.

Development

Field	WI	Operator	Estimated gross reserves	Production start expected	Expected gross plateau production
Johan Sverdrup	22.6%	Equinor	2.2 – 3.2 Bn boe	November 2019	660 Mbopd
Solveig Phase 1	65%	Lundin Norway	57 MMboe	Q1 2021	30 Mboepd
Rolvsnes EWT	50%1	Lundin Norway	-	Q2 2021	3 Mboepd

1 Lundin's working interest will increase to 80% on completion of the Lime Petroleum transaction

Johan Sverdrup

Phase 1 of the Johan Sverdrup project continues to progress according to schedule and is now over 85 percent complete. A major milestone was achieved in March 2019 with the successful installation of the processing platform topsides and the living quarters topsides using the Pioneering Spirit installation vessel. Two connecting bridges were also successfully installed. This operation concludes the main installation activities for Phase 1 of the project, which consists of four jackets and topsides, three subsea water injection templates, oil and gas export pipelines and power supply from shore. Hook-up and commissioning of the field centre will now take place, alongside the tie-back of the eight pre-drilled production wells. Two accommodation units are located offshore, which together with the newly installed living quarters will at peak allow for approximately 1,000 personnel working on the hook-up and commissioning of the facilities. With the successful installation of the remaining facilities, the project is firmly on track to achieve expected first oil in November 2019. The gross production capacity of Phase 1 is estimated at 440 Mbopd, with ramp-up to plateau production levels expected to take until summer 2020.

The capital expenditure estimate for Phase 1 as at August 2018 is gross NOK 86 billion (nominal) compared to the Phase 1 PDO estimate in 2015 of gross NOK 123 billion (nominal), representing a saving of over 30 percent, excluding additional foreign exchange rate savings in US dollar terms.

The Phase 2 PDO was submitted to the Norwegian Ministry of Petroleum and Energy in August 2018 and is expected to be approved during the second quarter of 2019. Phase 2 involves a second processing platform bridge linked to the Phase 1 field centre, subsea facilities to allow for tie-in of additional wells to access the Avaldsnes, Kvitsøy and Geitungen satellite areas of the field and implementation of full field water alternating gas injection (WAG) for enhanced recovery. 28 new wells are planned to be drilled in connection with the Phase 2 development. Phase 2 first oil is scheduled in the fourth quarter 2022 and will take the gross plateau production capacity to 660 Mbopd. Full field breakeven oil price is estimated at below 20 USD per barrel.

The Phase 2 capital expenditure is estimated at gross NOK 41 billion (nominal), which is unchanged from the Phase 2 PDO estimate and over a 50 percent saving from the original estimate in the Phase 1 PDO. Phase 2 of the project is progressing to plan and the major topsides contracts and the jacket contract for the Phase 2 facilities, as well as the contract for the Subsea Production System, have been awarded. Detailed engineering is progressing on schedule and construction of the second processing platform has started with first steel cut at Aibel's construction yard in Thailand in March 2019.

Greater Edvard Grieg Area Tie-Back Projects

The PDO for the Solveig Phase 1 project was submitted to the Norwegian Ministry of Petroleum and Energy in March 2019 and is anticipated to be approved during the second quarter of 2019. Solveig 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 will be developed with three oil production wells and two water injection wells and will achieve gross peak production of 30 Mboepd, with first oil scheduled in the first quarter 2021.

Solveig Phase 1 gross proved plus probable reserves are estimated at 57 MMboe. The capital cost of the development is estimated at MUSD 810 gross with a breakeven oil price of below 30 USD per barrel. The potential for further phases of development, which will capture the upside potential in the discovered resources, will be derisked by production performance from Phase 1.

The Solveig Phase 1 project is progressing to plan. All of the key contracts have been awarded and modifications at the Edvard Grieg platform will commence during the second quarter 2019.

The production application for the Rolvsnes Extended Well Test (EWT) was submitted in April 2019. The Rolvsnes EWT project will be conducted through a 3 km subsea tie-back of the existing Rolvsnes horizontal well to the Edvard Grieg platform. The project is being implemented together with the Solveig project to take advantage of contracting and implementation synergies, with first oil scheduled in the second quarter 2021. The on-trend Goddo prospect is planned to be drilled in the second quarter 2019, with the combined Rolvsnes and Goddo prospective area estimated to contain gross potential resources of more than 250 MMboe.

Appraisal

2019 appraisal well programme

Licence	Operator	WI	Well	Spud Date	Status
PL167	Equinor	20%	Lille Prinsen	Second Quarter 2019

The appraisal well that was planned on Alta/Gohta in 2019 has been deferred to 2020 to allow additional time to complete the technical work required to assess the forward appraisal strategy. Lundin has a flexible contract for the Leiv Eiriksson drilling rig with sufficient optional slots to meet the Company's operated 2019 drilling programme. The deferral of the Alta/Gohta appraisal well has allowed the Leiv Eiriksson rig to be utilised by ConocoPhillips to accelerate into 2019 the drilling of two exploration wells in PL917 in which Lundin Petroleum has an interest.

Exploration

2019 exploration well programme

Licence	Operator	WI	Well	Spud Date	Result
PL857	Equinor	20%	Gjøkåsen Shallow	December 2018	Dry
PL767	Lundin Norway	50%	Pointer/Setter	January 2019	Dry
PL869	AkerBP	20%	Froskelår Main	January 2019	Oil & Gas Discovery
PL857	Equinor	20%	Gjøkåsen Deep	February 2019	Dry
PL338	Lundin Norway	65%	Jorvik/Tellus East	March 2019	Ongoing
PL869	AkerBP	20%	Froskelår North East	March 2019	Ongoing
PL539	MOL	20%	Vinstra/Otta	April 2019	Ongoing
PL916	AkerBP	20%	JK	April 2019	Ongoing
PL859	Equinor	15%	Korpfjell Deep	Second Quarter 2019
PL8151	Lundin Norway	40%	Goddo	Second Quarter 2019
PL758	Capricorn	20%	Lynghaug	Second Quarter 2019
PL869	AkerBP	20%	Rumpetroll	Third Quarter 2019
PL820S	MOL	30%	Evra/Iving	Third Quarter 2019
PL896	DEA	20%	Toutatis	Third Quarter 2019
PL921	Equinor	15%	Gladsheim	Fourth Quarter 2019
PL917	ConocoPhillips	20%	Enniberg	Fourth Quarter 2019
PL917	ConocoPhillips	20%	Hasselbaink	Fourth Quarter 2019

1 Lundin's working interest will increase to 60% on closing of the Lime Petroleum transaction

Due to changing priorities, the 2019 exploration drilling programme has been increased to 17 wells, of which four have been completed yielding one oil discovery. The remaining programme is targeting net unrisked resources of over 400 MMboe. The appraisal and exploration spend guidance for 2019 is being maintained at MUSD 300.

In February 2019, the Gjøkåsen Shallow prospect in PL857 in the southeastern Barents Sea was drilled and was dry.

In February 2019, the Pointer/Setter dual target prospect in PL767 located in the southern Barents Sea was drilled and was dry.

In March 2019, the Froskelår Main prospect in PL869 in the Alvheim area proved an oil and gas discovery. The discovery is estimated to contain gross resources of between 60 and 130 MMboe with part of the discovery potentially extending into the UK. Froskelår Main will be evaluated as part of a potential joint development with the Frosk discovery.

In March 2019, drilling commenced on a dual branch well targeting the Jorvik and Tellus East prospects on the eastern side of the Edvard Grieg field in PL338. The well is targeting extensions of the same reservoirs found at Edvard Grieg; conglomerates/pebbly sandstones in the Jorvik prospect and weathered and fractured basement potentially draped by sandstones in the Tellus East prospect. The two prospects combined are estimated to contain gross unrisked prospective resources of 23 MMboe and if successful can be developed with wells drilled from the Edvard Grieg platform.

In April 2019, the Gjøkåsen Deep prospect in PL857 in the southeastern Barents Sea was drilled and was dry.

In April 2019, drilling commenced on the dual target Vinstra/Otta prospect in PL539 located in the Mandal High area of the North Sea. Vinstra is targeting Permian Rotliegendes sandstones and Otta is a Jurassic sandstone target, with combined gross unrisked prospective resources of 555 MMboe.

In April 2019, drilling commenced on the JK prospect in PL916 located in the north of the Utsira High area of the North Sea. The main target of the well is Jurassic Statfjord sandstones with gross unrisked prospective resources of 243 MMboe.

Decommissioning

Preparation of the decommissioning plan for the Brynhild field is ongoing with operations anticipated to be conducted during 2020/2021. The Rowan Viking jack-up drilling rig has been secured to plug and abandon the four Brynhild development wells.

The Gaupe field ceased production during the fourth quarter of 2018 and preparation of the decommissioning plan for the field is also ongoing.

Licence awards and transactions

In January 2019, Lundin Petroleum was awarded 15 licences in the 2018 APA licensing round, of which nine are as operator.

In January 2019, Lundin Petroleum entered into a sales and purchase agreement involving the acquisition of Lime Petroleum's 30 percent working interest in each of PL338C and PL338E and 20 percent working interest in PL815, which contain the Rolvsnes oil discovery and Goddo prospect. The transaction will increase the Company's working interest in each of PL338C and PL338E to 80 percent and in PL815 to 60 percent. The transaction involves a cash consideration payable to Lime Petroleum and is subject to customary government approvals. The transaction is expected to complete in mid 2019, with economic effect from 1 January 2019.

Lundin Petroleum has applied for a possible extension area of the Mandal High prospectivity into Denmark in the 8th Danish licensing round where confirmation of awards are expected during the second quarter of 2019.

Currently the Company holds 80 licences in Norway, which is an increase of approximately 65 percent from the beginning of 2018.

Russia

Lundin Petroleum has previously written down the entire contingent resources and book value for the Morskaya oil discovery in Russia, as it was deemed unlikely that the discovery could commercially be developed in the foreseeable future. Having reviewed potential options, the partnership concluded that it is not possible for the partnership to create value from the asset and consequently the Morskaya licence has been relinquished.

Health, Safety and Environment

During the reporting period, there were no recordable safety incidents and no material environmental incidents. The trend of industry leading low carbon operations continued at the Edvard Grieg field with a carbon intensity of 4.5 kgCO2e/boe during the first quarter of 2019.

FINANCIAL REVIEW

Result

The operating profit for the reporting period amounted to MUSD 267.2 (MUSD 337.6). The decrease compared to the comparative period was mainly driven by expensed exploration costs during the reporting period and slightly lower production volumes and oil prices, somewhat offset by lower depletion costs.

The net result for the reporting period amounted to MUSD 54.9 (MUSD 228.8) representing earnings per share of USD 0.16 (USD 0.68) and impacted by a lower foreign currency exchange gain of MUSD 0.8 (MUSD 162.1). The net result excluding foreign currency exchange results amounted to MUSD 54.1 (MUSD 66.7).

Earnings before interest, tax, depletion and amortisation (EBITDA) for the reporting period amounted to MUSD 406.0 (MUSD 456.5) representing EBITDA per share of USD 1.20 (USD 1.35). Operating cash flow for the reporting period amounted to MUSD 385.0 (MUSD 461.8) representing operating cash flow per share of USD 1.14 (USD 1.36). Free cash flow for the reporting period amounted to MUSD 95.8 (MUSD 171.8) representing free cash flow per share of USD 0.28 (USD 0.51).

Changes in the Group

In January 2019, Lundin Petroleum entered into a sales and purchase agreement for the acquisition of Lime Petroleum's 30 percent working interest in each of PL338C and PL338E and 20 percent working interest in PL815, which contain the Rolvsnes oil discovery and Goddo prospect. The transaction will increase the Company's working interest in each of PL338C and PL338E to 80 percent and in PL815 to 60 percent. The transaction involves a cash consideration payable to Lime Petroleum of MUSD 43 and a contingent payment of an additional MUSD 2 which potentially becomes payable 12 months after the completion date of the transaction. The transaction is subject to customary government approvals.

Revenue and other income

Revenue and other income for the reporting period amounted to MUSD 491.6 (MUSD 692.9) and was comprised of net sales of oil and gas, change in under/over lift position and other revenue as detailed in Note 1.

Net sales of oil and gas for the reporting period amounted to MUSD 476.5 (MUSD 694.2). The average price achieved by Lundin Petroleum for a barrel of oil equivalent from own production amounted to USD 60.88 (USD 64.53) and is detailed in the following table. The average Dated Brent price for the reporting period amounted to USD 63.13 (USD 66.82) per barrel.

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

Sales from own production Average price per boe expressed in USD	1 Jan 2019- 31 Mar 2019 3 months	1 Jan 2018- 31 Mar 2018 3 months	1 Jan 2018- 31 Dec 2018 12 months
Crude oil sales
– Quantity in Mboe	5,998.5	6,958.1	26,834.7
– Average price per bbl	64.78	66.23	69.97
Gas and NGL sales – Quantity in Mboe – Average price per boe	1,169.2 40.87	782.9 51.01	3,682.0 52.74
Total sales
– Quantity in Mboe	7,167.7	7,741.0	30,516.7
– Average price per boe	60.88	64.53	67.89

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 40.1 (MUSD 193.4) and consisted of Grane Blend crude oil purchased from outside the Group by Lundin Petroleum Marketing SA and sold to the market.

Sales of oil and gas are recognised when the risk of ownership is transferred to the purchaser. 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 amounted to an income of MUSD 7.5 (expense of MUSD 9.5) in the reporting period due to the timing of the cargo liftings compared to production.

Other income for the reporting period amounted to MUSD 7.6 (MUSD 8.2) and included a quality differential compensation on Alvheim blended crude and tariff income of MUSD 7.0 (MUSD 7.6) which is due to net income from Ivar Aasen tariffs paid to Edvard Grieg.

Production costs

Production costs including inventory movements for the reporting period amounted to MUSD 40.1 (MUSD 38.6) and are detailed in Note 2. The total production cost per barrel of oil equivalent produced is detailed in the table below:

Production costs	1 Jan 2019- 31 Mar 2019 3 months	1 Jan 2018- 31 Mar 2018 3 months	1 Jan 2018- 31 Dec 2018 12 months
Cost of operations
– In MUSD	28.0	27.3	102.5
– In USD per boe	3.95	3.65	3.46
Tariff and transportation expenses
– In MUSD	11.0	8.9	35.2
– In USD per boe	1.55	1.18	1.19
Operating costs
– In MUSD	39.0	36.2	137.7
– In USD per boe1	5.50	4.83	4.65
Change in inventory position
– In MUSD	0.0	0.6	0.6
– In USD per boe	0.00	0.08	0.02
Other
– In MUSD	1.1	1.8	7.1
– In USD per boe	0.15	0.24	0.24
Production costs
– In MUSD	40.1	38.6	145.4
– In USD per boe	5.65	5.15	4.91

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 Petroleum's operating cost for the reporting period of USD 5.50 (USD 4.83) per barrel is reduced to USD 4.51 (USD 3.82) when tariff income is netted off.

The total cost of operations for the reporting period amounted to MUSD 28.0 (MUSD 27.3) and the total cost of operations excluding operational projects amounted to MUSD 25.1 (MUSD 24.9).

The cost of operations per barrel for the reporting period amounted to USD 3.95 (USD 3.65) including operational projects and USD 3.54 (USD 3.33) excluding operational projects.

Tariff and transportation expenses for the reporting period amounted to MUSD 11.0 (MUSD 8.9) or USD 1.55 (USD 1.18) per barrel. The increase compared to the comparative period is driven by higher pipeline tariff rates in combination with freight costs for crude oil sales.

Other costs for the reporting period amounted to MUSD 1.1 (MUSD 1.8) and related to the business interruption insurance.

Depletion and decommissioning costs

Depletion and decommissioning costs for the reporting period amounted to MUSD 99.8 (MUSD 118.5) at an average rate of USD 14.08 (USD 15.84) per barrel and are detailed in Note 3. The lower depletion costs for the reporting period compared to the comparative period is due to lower production volumes in combination with a lower depletion rate per barrel in USD terms as the depletion rate per barrel is calculated in Norwegian Kroner and with the Norwegian Kroner having weakened the USD depletion rate has been reduced.

Exploration costs

Exploration costs expensed in the income statement for the reporting period amounted to MUSD 37.3 (MUSD -0.3) and are detailed in Note 3. Exploration and appraisal costs are capitalised as they are incurred. When exploration drilling is unsuccessful, the capitalised costs are expensed. All capitalised exploration costs are reviewed on a regular basis and are expensed where their recoverability is considered highly uncertain.

Purchase of crude oil from third parties

Purchase of crude oil from third parties for the reporting period amounted to MUSD 40.1 (MUSD 192.2) and related to Grane Blend 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 7.1 (MUSD 6.3) which included a charge of MUSD 1.4 (MUSD 1.0) in relation to the Group's long-term incentive plans (LTIP), see also Remuneration section below. Fixed asset depreciation expenses for the reporting period amounted to MUSD 1.7 (MUSD 0.7) with the increase compared to the comparative period mainly caused by the implementation of IFRS 16 with effective date 1 January 2019 based on which depreciation expenses relating to right of use assets are included in the reporting period.

Finance income

Finance income for the reporting period amounted to MUSD 9.1 (MUSD 162.4) and is detailed in Note 4.

The net foreign currency exchange gain for the reporting period amounted to MUSD 0.8 (MUSD 162.1). 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 Petroleum has hedged certain foreign currency capital expenditure amounts against the US Dollar and for the reporting period, the net realised exchange loss on these settled foreign exchange hedges amounted to MUSD 3.8 (gain of MUSD 5.4).

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

The result on interest rate hedge settlements amounted to a gain of MUSD 7.9 (loss of MUSD 2.0).

Finance costs

Finance costs for the reporting period amounted to MUSD 39.9 (MUSD 39.0) and are detailed in Note 5.

Interest expenses for the reporting period amounted to MUSD 16.8 (MUSD 24.5) and represented the portion of interest charged to the income statement. An additional amount of interest of MUSD 24.2 (MUSD 21.6) associated with the funding of the Norwegian development projects was capitalised in the reporting period. The total interest expense reduced compared to the comparative period mainly due to lower drawn debt under the reserve-based lending facility.

The amortisation of the deferred financing fees for the reporting period amounted to MUSD 4.2 (MUSD 4.6) and related to the fees incurred in establishing the reserve-based lending facility. The fees are being expensed over the expected life of the facility.

Loan facility commitment fees for the reporting period amounted to MUSD 3.4 (MUSD 3.5) with the lower drawn debt under the reserve-based lending facility compared to the comparative period being offset by a lower margin for commitment fees as agreed through the amendment of the facility effective as of 1 June 2018.

The unwinding of the loan modification gain for the reporting period amounted to MUSD 10.6 (MUSD –) 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. During 2018, the reserve-based lending facility was successfully re-negotiated resulting in the interest rate margin over LIBOR being reduced from 3.15 percent to a current rate of 2.25 percent effective as of 1 June 2018. The amendment of the interest rate margin resulted in an accounting gain of MUSD 183.7 during 2018 in accordance with IFRS 9.

Share in result of associate company

Share in result of associated company for the reporting period amounted to MUSD -0.2 (MUSD -0.0) and related to the share in the result of the investment in Mintley Caspian Ltd.

Tax

The overall tax charge for the reporting period amounted to MUSD 181.3 (MUSD 232.2) and is detailed in Note 6.

The current tax charge for the reporting period amounted to MUSD 26.4 (MUSD 0.3) of which MUSD 26.3 (MUSD –) related to Norway. The current tax charge for Norway related to Corporate Tax only with no current tax charge to the income statement in relation to the Special Petroleum Tax (SPT) as the Company continues to be sheltered from SPT tax losses. The paid tax installments in Norway during the reporting period amounted to MUSD 6.4 which has resulted in an increase in current tax liabilities compared to the comparative period.

The deferred tax charge for the reporting period amounted to MUSD 154.9 (MUSD 231.9) and related to Norway. The deferred tax amount arises primarily where there is a difference in depletion for tax and accounting purposes.

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 12.5 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.

Balance Sheet

Non-current assets

Oil and gas properties amounted to MUSD 5,569.5 (MUSD 5,341.1) and are detailed in Note 7.

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

Development expenditure in MUSD	1 Jan 2019- 31 Mar 2019 3 months	1 Jan 2018- 31 Mar 2018 3 months	1 Jan 2018- 31 Dec 2018 12 months
Norway	161.7	171.0	701.9
Development expenditures	161.7	171.0	701.9

Development expenditure of MUSD 161.7 (MUSD 171.0) was incurred in Norway during the reporting period, primarily on the Johan Sverdrup field. In addition an amount of MUSD 24.2 (MUSD 21.6) of interest was capitalised.

Exploration and appraisal expenditure in MUSD	1 Jan 2019- 31 Mar 2019 3 months	1 Jan 2018- 31 Mar 2018 3 months	1 Jan 2018- 31 Dec 2018 12 months
Norway	87.3	54.1	310.6
Exploration and appraisal expenditure	87.3	54.1	310.6

Exploration and appraisal expenditure of MUSD 87.3 (MUSD 54.1) was incurred in Norway during the reporting period, primarily for the exploration wells Gjøkåsen Shallow and Gjøkåsen Deep in PL857, Pointer/Setter in PL767, Froskelår in PL869 and Jorvik/Tellus East in PL338.

Other tangible fixed assets amounted to MUSD 49.0 (MUSD 13.6) and are detailed in Note 8. Following the implementation of IFRS 16 with effective date 1 January 2019, the company recognized right of use assets that amounted to MUSD 35.9 (MUSD –).

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

Derivative instruments amounted to MUSD 0.5 (MUSD 2.7) and related to the marked-to-market gain on the outstanding interest rate hedge contracts due to be settled after twelve months.

Current assets

Inventories amounted to MUSD 39.4 (MUSD 36.5) and included both well supplies and hydrocarbon inventories.

Trade and other receivables amounted to MUSD 272.4 (MUSD 219.3) and are detailed in Note 9. Trade receivables, which are all current, amounted to MUSD 203.2 (MUSD 153.7) and included invoiced cargoes. Underlift amounted to MUSD 10.9 (MUSD 4.6) and was attributable to an underlift position on the producing fields, mainly from the Alvheim area. Joint operations debtors relating to various joint venture receivables amounted to MUSD 12.3 (MUSD 17.0). Prepaid expenses and accrued income amounted to MUSD 30.0 (MUSD 26.9) and represented mainly prepaid operational and insurance expenditure. Other current assets amounted to MUSD 16.0 (MUSD 17.1) and included a short term receivable from IPC in relation to certain working capital balances following the IPC spin-off amounting to MUSD 14.1 and other miscellaneous receivable balances.

Derivative instruments amounted to MUSD 23.5 (MUSD 34.0) and related to the marked-to-market gain on the outstanding interest rate hedge contracts due to be settled within twelve months.

Cash and cash equivalents amounted to MUSD 91.3 (MUSD 66.8) of which MUSD 10.8 (MUSD –) is restricted. Cash balances are mainly held to meet ongoing operational funding requirements.

Non-current liabilities

Financial liabilities amounted to MUSD 3,236.0 (MUSD 3,262.0) and are detailed in Note 10. Bank loans amounted to MUSD 3,395.0 (MUSD 3,465.0) and related to the outstanding loan under the reserve-based lending facility. Capitalised financing fees relating to the establishment of the facility amounted to MUSD 50.5 (MUSD 54.1) and are being amortised over the expected life of the facility. The capitalised loan modification gain relating to the re-negotiated improved borrowing terms for the lending facility during 2018 amounted to MUSD 139.3 (MUSD 148.9) and are being amortised over the expected life of the facility. The lease commitments amounted to MUSD 30.8 (MUSD –) and related to the long-term portion of the lease commitments following the implementation of IFRS 16 with effective date 1 January 2019. The short-term portion of the lease commitments was classified as current liabilities.

Provisions amounted to MUSD 532.3 (MUSD 489.1) and are detailed in Note 11. The provision for site restoration amounted to MUSD 525.0 (MUSD 483.9) and related to the long-term portion of the future decommissioning obligations. The increase mainly reflects the additional liability for the Johan Sverdrup development project with the installation of two platforms during the reporting period. The short-term portion of the future decommissioning obligations was classified as current liabilities.

Deferred tax liabilities amounted to MUSD 2,279.9 (MUSD 2,103.0). 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 78.9 (MUSD 64.9) 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 5.3 (MUSD –) and are detailed in Note 10.

Dividends amounted to MUSD 501.2 (MUSD –) and related to the cash dividend approved by the AGM held on 29 March 2019 in Stockholm, which will be paid in quarterly installments.

Trade and other payables amounted to MUSD 243.4 (MUSD 204.6) and are detailed in Note 12. Overlift amounted to MUSD 4.2 (MUSD 5.4) and was attributable to an overlift position in relation to the Edvard Grieg field. Joint operations creditors and accrued expenses amounted to MUSD 177.7 (MUSD 147.4) and related to activity in Norway. Other accrued expenses amounted to MUSD 16.8 (MUSD 17.6) and other current liabilities amounted to MUSD 6.9 (MUSD 7.6).

Derivative instruments amounted to MUSD 20.0 (MUSD 20.0) 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 91.1 (MUSD 70.4) and related mainly to Corporate Tax due in Norway.

Current provisions amounted to MUSD 16.3 (MUSD 12.5) and are detailed in Note 11. The short-term portion of the future decommissioning obligations amounted to MUSD 6.6 (MUSD 6.6) and the current portion of the provision for Lundin Petroleum's Unit Bonus Plan amounted to MUSD 9.7 (MUSD 5.9).

Parent Company

The business of the Parent Company is investment in and management of oil and gas assets. The net result for the Parent Company for the reporting period amounted to MSEK 4,603.8 (MSEK -15.4). The net result for the reporting period included MSEK 4,638.1 (MSEK –) financial income as a result of received dividends from a subsidiary. The net result excluding received dividends amounted to MSEK - 34.3 (MSEK -15.4).

The net result for the reporting period included general and administrative expenses of MSEK 42.3 (MSEK 27.2) and net finance income of MSEK 0.6 (MSEK 4.5) 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 Petroleum Holding BV, see also the Liquidity section below.

Related Party Transactions

During the reporting period, the Group has entered into various transactions with related parties on a commercial basis including the transactions described below.

The Group has purchased oil from the Equinor group on an arm's-length basis amounting to MUSD – (MUSD 112.2).

The Group has sold oil and related products to the Equinor group on an arm's-length basis amounting to MUSD 50.6 (MUSD 340.2).

As at the date of the IPC spin-off, the Group had a residual receivable for working capital from IPC of MUSD 27.4, which has been reduced to MUSD 14.1. This receivable is due by mid-2019.

Liquidity

In February 2016, Lundin Petroleum 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 2.25 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 licenses and a charge over some of the bank accounts of the pledged companies.

Contingent liabilities

The Swedish Prosecution Authority issued a notification of a corporate fine and forfeiture of economic benefits against Lundin Petroleum 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 ninth year and Lundin Petroleum 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

There are no subsequent events to report.

Share Data

Lundin Petroleum AB's issued share capital amounted to SEK 3,478,713 represented by 340,386,445 shares with a quota value of SEK 0.01 each (rounded off).

During 2017, Lundin Petroleum 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 Petroleum 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 resulting in 1,873,310 of its own shares held by the Company.

The AGM of Lundin Petroleum held on 29 March 2019 in Stockholm approved a cash dividend distribution for the year 2018 of USD 1.48 per share, to be paid in quarterly installments of USD 0.37 per share. Before payment, each quarterly dividend of USD 0.37 per share shall be converted into a SEK amount, and paid out in SEK, based on the USD to SEK exchange rate published by Sweden's central bank (Riksbanken) four business days prior to each record date (rounded off to the nearest whole SEK 0.01 per share). The final USD equivalent amount received by the shareholders may therefore slightly differ depending on what the USD to SEK exchange rate is on the date of the dividend payment. Based on the number of shares outstanding, excluding own shares held by the Company, the approved dividend distribution amounted to MSEK 4,638.7, equaling MUSD 501.0 based on the exchange rate on the date of AGM approval.

The first dividend payment was paid on 5 April 2019. The second dividend payment is expected to be paid around 8 July 2019, with an expected record date of 3 July 2019 and expected ex-dividend date of 2 July 2019. The third dividend payment is expected to be paid around 7 October 2019, with an expected record date of 2 October 2019 and an expected ex-dividend date of 1 October 2019. The fourth dividend payment is expected to be paid around 9 January 2020, with an expected record date of 3 January 2020 and an expected ex-dividend date of 2 January 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 2018 dividend has been set to a cap of SEK 7.665 billion (i.e., SEK 1.916 billion per quarter). If the total dividend would exceed the cap of SEK 7.665 billion, the dividend will be automatically adjusted downwards so that the total dividend corresponds to the cap of SEK 7.665 billion.

Remuneration

Lundin Petroleum's principles for remuneration and details of the long-term incentive plans are provided in the Company's 2018 Annual Report and in the materials provided to shareholders in respect of the 2019 AGM, available on www.lundin-petroleum.com

Unit Bonus Plan

The number of units relating to the awards made in 2016, 2017 and 2018 under the Unit Bonus Plan outstanding as at 31 March 2019 were 107,794, 188,064 and 226,389 respectively.

Performance Based Incentive Plan

The AGM 2018 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 2018 and the 2018 award is accounted for from the second half of 2018. The total outstanding number of awards at 31 March 2019 was 278,917 and the awards vest over three years from 1 July 2018 subject to certain performance conditions being met. Each original award was fair valued at the date of grant at SEK 167.10 using an option pricing model.

The 2017 plan is effective from 1 July 2017 and the total outstanding number of awards at 31 March 2019 was 355,954 and the awards vest over three years from 1 July 2017 subject to certain performance conditions being met. Each original award was fair valued at the date of grant at SEK 100.10 using an option pricing model.

The 2016 plan is effective from 1 July 2016 and the total outstanding number of awards at 31 March 2019 was 409,343 and the awards vest over three years from 1 July 2016 subject to certain performance conditions being met. The outstanding number of awards increased compared to the original number of awards as a result of the dividend distribution of the IPC business as per the plan rules. Each original award was fair valued at the date of grant at SEK 89.30 using an option pricing model. Awards given to employees now employed by IPC following the IPC spin-off have been pro-rated until the spin-off date 24 April 2017.

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).

IFRS 16 has come into effect with effective date 1 January 2019. IFRS16 Leases, addresses the recognition in the balance sheet of each contract, with some exceptions, that meets the definition of a lease as a right of use asset and lease liability, while lease payments are to be reflected as interest expense and a reduction of lease liability. The Group has made the following transition choices in relation to IFRS 16: (a) application of the modified retrospective method, (b) right of use assets are measured at an amount equal to the lease liability and (c) leases with a less than 12 months remaining lease term at year end 2018 are not reflected as leases. The Group has made the following application policy choice: short term leases (less than 12 months) and leases of low value assets are not reflected in the balance sheet, but will be expensed as incurred.

Lundin Petroleum has assessed the impact of IFRS 16 on the financial statements of the Group and only identified one relevant contract containing a lease with no material impact on the financial statements of the Group. The Company accounted for right of use assets and lease commitments amounting to MUSD 36.6 per effective date 1 January 2019.

The accounting policies adopted are in all other aspects consistent with those followed in the preparation of the Group's annual financial statements for the year ended 31 December 2018.

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 reporting 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 Petroleum's strategic, operational, financial and external risks and mitigation of those risks through risk management is described in Lundin Petroleum's 2018 Annual Report.

Derivative financial instruments

Lundin Petroleum has entered into forward currency hedges to meet part of its future NOK capital requirements relating to its committed field development projects and to meet part of its future NOK Corporate Tax requirements. At 31 March 2019, Lundin Petroleum had outstanding currency hedges as summarised below:

Buy	Sell	Average contractual Exchange rate	Settlement period
MNOK 2,994.0	MUSD 363.6	NOK 8.23:USD 1	Apr 2019 – Dec 2019
MNOK 2,405.0	MUSD 306.0	NOK 7.86:USD 1	Jan 2020 – Dec 2020
MNOK 2,130.0	MUSD 272.7	NOK 7.81:USD 1	Jan 2021 – Dec 2021
MNOK 1,200.0	MUSD 158.2	NOK 7.59:USD 1	Jan 2022 – Dec 2022
MNOK 410.0	MUSD 51.0	NOK 8.04:USD 1	Jan 2023 – Dec 2023

Lundin Petroleum entered into interest rate hedge contracts and at 31 March 2019 had outstanding interest rate hedge contracts as follows:

Borrowings expressed in MUSD	Fixing of floating LIBOR average rate per annum	Settlement period
3,000	1.42%	Apr 2019 – Dec 2019
2,000	2.15%	Jan 2020 – Dec 2020
2,000	2.67%	Jan 2021 – Dec 2021
2,000	2.74%	Jan 2022 – Dec 2022

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

Exchange Rates

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

	31 Mar 2019		31 Mar 2018		31 Dec 2018
	Average	Period end	Average	Period end	Average	Period end
1 USD equals NOK	8.5784	8.5972	7.8358	7.7773	8.1329	8.6885
1 USD equals Euro	0.8806	0.8901	0.8134	0.8116	0.8464	0.8734
1 USD equals SEK	9.1781	9.2550	8.1117	8.3470	8.6921	8.9562

Consolidated Income Statement

		1 Jan 2019- 31 Mar 2019	1 Jan 2018- 31 Mar 2018	1 Jan 2018- 31 Dec 2018
Expressed in MUSD	Note	3 months	3 months	12 months
Revenue and other income	1
Revenue		476.5	694.2	2,607.9
Other income		15.1	-1.3	9.5
		491.6	692.9	2,617.4
Cost of sales
Production costs	2	-40.1	-38.6	-145.4
Depletion and decommissioning costs		-99.8	-118.5	-458.0
Exploration costs		-37.3	0.3	-53.2
Purchase of crude oil from third parties		-40.1	-192.2	-533.8
Gross profit	3	274.3	343.9	1,427.0
General, administration and depreciation expenses		-7.1	-6.3	-24.6
Operating profit		267.2	337.6	1,402.4
Net financial items
Finance income	4	9.1	162.4	192.2
Finance costs	5	-39.9	-39.0	-345.4
		-30.8	123.4	-153.2
Share in result of associated company		-0.2	-0.0	-1.3
Profit before tax		236.2	461.0	1,247.9
Income tax	6	-181.3	-232.2	-1,025.8
Net result		54.9	228.8	222.1
Attributable to:
Shareholders of the Parent Company		54.9	228.8	222.1
Non-controlling interest		–	–	–
		54.9	228.8	222.1
Earnings per share – USD		0.16	0.68	0.66
Earnings per share fully diluted – USD		0.16	0.67	0.65

Consolidated Statement of Comprehensive Income

Expressed in MUSD	1 Jan 2019- 31 Mar 2019 3 months	1 Jan 2018- 31 Mar 2018 3 months	1 Jan 2018- 31 Dec 2018 12 months
Net result	54.9	228.8	222.1
Items that may be subsequently reclassified to profit or loss:
Exchange differences foreign operations	26.6	-8.9	1.5
Cash flow hedges	-27.9	65.4	-74.1
Other comprehensive income, net of tax	-1.3	56.5	-72.6
Total comprehensive income	53.6	285.3	149.5
Attributable to:
Shareholders of the Parent Company	53.6	285.3	149.5
Non-controlling interest	–	–	–
	53.6	285.3	149.5

Consolidated Balance Sheet

Expressed in MUSD	Note	31 March 2019	31 December 2018
ASSETS
Non-current assets
Oil and gas properties	7	5,569.5	5,341.1
Other tangible fixed assets	8	49.0	13.6
Goodwill		128.1	128.1
Financial assets		0.4	0.4
Derivative instruments	13	0.5	2.7
Total non-current assets		5,747.5	5,485.9
Current assets
Inventories	9	39.4	36.5
Trade and other receivables Derivative instruments	13	272.4 23.5	219.3 34.0
Cash and cash equivalents		91.3	66.8
Total current assets		426.6	356.6
TOTAL ASSETS		6,174.1	5,842.5
EQUITY AND LIABILITIES
Equity
Shareholders´ equity		-830.3	-384.0
Liabilities
Non-current liabilities
Financial liabilities	10	3,236.0	3,262.0
Provisions	11	532.3	489.1
Deferred tax liabilities		2,279.9	2,103.0
Derivative instruments	13	78.9	64.9
Total non-current liabilities		6,127.1	5,919.0
Current liabilities
Financial liabilities	10	5.3	–
Dividends		501.2	–
Trade and other payables	12	243.4	204.6
Derivative instruments	13	20.0	20.0
Current tax liabilities		91.1	70.4
Provisions	11	16.3	12.5
Total current liabilities		877.3	307.5
Total liabilities		7,004.4	6,226.5
TOTAL EQUITY AND LIABILITIES		6,174.1	5,842.5

Consolidated Statement of Cash Flows

Expressed in MUSD	1 Jan 2019- 31 Mar 2019 3 months	1 Jan 2018- 31 Mar 2018 3 months	1 Jan 2018- 31 Dec 2018 12 months
Cash flows from operating activities
Net result	54.9	228.8	222.1
Adjustments for:
Exploration costs	37.3	-0.3	53.2
Depletion, depreciation and amortisation	101.5	119.2	460.6
Current tax	26.4	0.3	90.4
Deferred tax	154.9	231.9	935.4
Long-term incentive plans	6.7	3.7	14.6
Foreign currency exchange gain/ loss	-4.6	-156.7	162.5
Interest expense	16.8	24.5	88.7
Loan modification gain	–	–	-183.7
Loan modification fees	–	–	17.3
Unwinding of loan modification gain	10.6	–	26.1
Capitalised financing fees	4.2	4.6	17.8
Other	4.2	3.6	12.8
Interest received	0.3	0.2	1.1
Interest paid	-40.9	-46.0	-176.0
Income taxes paid / received	-6.4	-0.3	-15.8
Changes in working capital	-20.1	-10.9	-8.8
Total cash flows from operating activities	345.8	402.6	1,718.3
Cash flows from investing activities
Investment in oil and gas properties	-249.0	-229.9	-1,060.1
Investment in other fixed assets	-0.1	-0.9	-3.2
Investment in other shares and participations1	–	–	9.3
Decommissioning costs paid	-0.9	–	-1.3
Total cash flows from investing activities	-250.0	-230.8	-1,055.3
Cash flows from financing activities
Changes in long-term bank loans	-70.0	-130.0	-490.0
Changes in lease commitments2	-0.9	–	–
Financing fees paid	–	–	-17.3
Dividends paid	–	–	-153.1
Purchase of own shares	–	-14.3	-14.3
Total cash flows from financing activities	-70.9	-144.3	-674.7
Change in cash and cash equivalents	24.9	27.5	-11.7
Cash and cash equivalents at the beginning
of the period	66.8	71.4	71.4
Currency exchange difference in cash and
cash equivalents	-0.4	1.7	7.1
Cash and cash equivalents at the end of the period	91.3	100.6	66.8

1 Cash received on the sale of the shares held in ShaMaran.

² Changes in lease commitments subsequent to initial recognition of lease commitments based on IFRS16

Consolidated Statement of Changes in Equity

		Additional
	Share	paid-in capital/Other	Retained
Expressed in MUSD	capital	reserves	earnings	Dividends	Total equity
At 1 January 2018	0.5	82.2	-433.5	–	-350.8
Comprehensive income
Net result	–	–	228.8	–	228.8
Other comprehensive income	–	56.5	–	–	56.5
Total comprehensive income	–	56.5	228.8	–	285.3
Transactions with owners
Purchase of own shares	–	-14.3	–	–	-14.3
Value of employee services	–	–	0.9	–	0.9
Total transactions with owners	–	-14.3	0.9	–	-13.4
At 31 March 2018	0.5	124.4	-203.8	–	-78.9
Comprehensive income
Net result	–	–	-6.7	–	-6.7
Other comprehensive income	–	-129.1	–	–	-129.1
Total comprehensive income	–	-129.1	-6.7	–	-135.8
Transactions with owners
Distributions	–	–	–	-153.1	-153.1
Share based payments	–	-20.8	–	–	-20.8
Value of employee services	–	–	4.6	–	4.6
Total transaction with owners	–	-20.8	4.6	-153.1	-169.3
At 31 December 2018	0.5	-25.5	-205.9	-153.1	-384.0
Transfer of prior year dividends	–	-153.1	–	153.1	–
Comprehensive income
Net result	–	–	54.9	–	54.9
Other comprehensive income	–	-1.3	–	–	-1.3
Total comprehensive income	–	-1.3	54.9	–	53.6
Transactions with owners
Distributions	–	–	–	-501.0	-501.0
Value of employee services	–	–	1.1	–	1.1
Total transaction with owners	–	–	1.1	-501.0	-499.9
At 31 March 2019	0.5	-179.9	-149.9	-501.0	-830.3

Notes to the Consolidated Financial Statements

Note 1 – Revenue and other income MUSD	1 Jan 2019- 31 Mar 2019 3 months	1 Jan 2018- 31 Mar 2018 3 months	1 Jan 2018- 31 Dec 2018 12 months
Revenue
Crude oil from own production	388.6	460.8	1,877.6
Crude oil from third party activities	40.1	193.4	536.1
Condensate	17.3	3.8	41.8
Gas	30.5	36.2	152.4
Sales of oil and gas	476.5	694.2	2,607.9
Other income
Change in under/over lift position	7.5	-9.5	-23.3
Other	7.6	8.2	32.8
Other income	15.1	-1.3	9.5
Revenue and other income	491.6	692.9	2,617.4

Note 2 – Production costs MUSD	1 Jan 2019- 31 Mar 2019 3 months	1 Jan 2018- 31 Mar 2018 3 months	1 Jan 2018- 31 Dec 2018 12 months
Cost of operations	28.0	27.3	102.5
Tariff and transportation expenses	11.0	8.9	35.2
Change in inventory position	–	0.6	0.6
Other	1.1	1.8	7.1
Production costs	40.1	38.6	145.4

Note 3 – Segment information MUSD	1 Jan 2019- 31 Mar 2019 3 months	1 Jan 2018- 31 Mar 2018 3 months	1 Jan 2018- 31 Dec 2018 12 months
Norway
Crude oil from own production	388.6	460.8	1,877.6
Condensate	17.3	3.8	41.8
Gas	30.5	36.2	152.4
Revenue	436.4	500.8	2,071.8
Change in under/over lift position	7.5	-9.5	-23.3
Other	7.6	8.2	32.8
Revenue and other income	451.5	499.5	2,081.3
Production costs	-40.1	-38.6	-145.4
Depletion and decommissioning costs	-99.8	-118.5	-458.0
Exploration costs	-37.3	0.3	-53.2
Gross profit	274.3	342.7	1,424.7
Other
Crude oil from third party activities	40.1	193.4	536.1
Revenue	40.1	193.4	536.1
Purchase of crude oil from third parties	-40.1	-192.2	-533.8
Gross profit	0.0	1.2	2.3

	1 Jan 2019-	1 Jan 2018-	1 Jan 2018-
Note 3 – Segment information cont.	31 Mar 2019	31 Mar 2018	31 Dec 2018
MUSD	3 months	3 months	12 months
Total
Crude oil from own production	388.6	460.8	1,877.6
Crude oil from third party activities	40.1	193.4	536.1
Condensate	17.3	3.8	41.8
Gas	30.5	36.2	152.4
Revenue	476.5	694.2	2,607.9
Change in under/over lift position	7.5	-9.5	-23.3
Other	7.6	8.2	32.8
Revenue and other income	491.6	692.9	2,617.4
Production costs	-40.1	-38.6	-145.4
Depletion and decommissioning costs	-99.8	-118.5	-458.0
Exploration costs	-37.3	0.3	-53.2
Purchase of crude oil from third parties	-40.1	-192.2	-533.8
Gross profit	274.3	343.9	1,427.0

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 2019- 31 Mar 2019 3 months	1 Jan 2018- 31 Mar 2018 3 months	1 Jan 2018- 31 Dec 2018 12 months
Foreign currency exchange gain, net	0.8	162.1	–
Loan modification gain	–	–	183.7
Interest income	0.4	0.2	1.7
Gain on interest rate hedge settlement	7.9	–	3.5
Other	–	0.1	3.3
Finance income	9.1	162.4	192.2

Note 5 – Finance costs MUSD	1 Jan 2019- 31 Mar 2019 3 months	1 Jan 2018- 31 Mar 2018 3 months	1 Jan 2018- 31 Dec 2018 12 months
Foreign currency exchange loss, net	–	–	164.9
Interest expense	16.8	24.5	88.7
Loss on interest rate hedge settlement	–	2.0	–
Unwinding of site restoration discount	4.4	3.9	16.4
Amortisation of deferred financing fees	4.2	4.6	17.8
Loan facility commitment fees	3.4	3.5	13.0
Loan modification fees	–	–	17.3
Unwinding of loan modification gain	10.6	–	26.1
Other	0.5	0.5	1.2
Finance costs	39.9	39.0	345.4
Note 6 – Income tax MUSD	1 Jan 2019- 31 Mar 2019 3 months	1 Jan 2018- 31 Mar 2018 3 months	1 Jan 2018- 31 Dec 2018 12 months
Current tax	26.4	0.3	90.4
Deferred tax	154.9	231.9	935.4
Income tax	181.3	232.2	1,025.8

Note 7 – Oil and gas properties MUSD	31 Mar 2019	31 Dec 2018
Norway
Producing assets	1,652.7	1,759.3
Assets under development	3,174.2	2,750.1
Capitalised exploration and appraisal expenditure	742.6	831.7
	5,569.5	5,341.1

Note 8 – Other tangible fixed assets

MUSD	31 Mar 2019	31 Dec 2018
Right of use assets	35.9	–
Other	13.1	13.6
	49.0	13.6

Note 9 – Trade and other receivables

MUSD	31 Mar 2019	31 Dec 2018
Trade receivables	203.2	153.7
Underlift	10.9	4.6
Joint operations debtors	12.3	17.0
Prepaid expenses and accrued income	30.0	26.9
Other	16.0	17.1
	272.4	219.3

Note 10 – Financial liabilities
MUSD	31 Mar 2019	31 Dec 2018
Non-current:
Bank loans	3,395.0	3,465.0
Capitalised financing fees	-50.5	-54.1
Capitalised loan modification gain	-139.3	-148.9
Lease commitments	30.8	–
	3,236.0	3,262.0
Current:
Lease commitments	5.3	–
	3,241.3	3,262,0

Note 11 – Provisions
MUSD	31 Mar 2019	31 Dec 2018
Non-current:
Site restoration	525.0	483.9
Long-term incentive plans	4.3	2.4
Other	3.0	2.8
	532.3	489.1
Current:
Site restoration	6.6	6.6
Long-term incentive plans	9.7	5.9
	16.3	12.5
	548.6	501.6

Note 12 – Trade and other payables MUSD 31 Mar 2019 31 Dec 2018 Trade payables 37.8 26.6 Overlift 4.2 5.4 Joint operations creditors and accrued expenses 177.7 147.4 Other accrued expenses 16.8 17.6 Other 6.9 7.6 243.4 204.6

Note 13 – Financial instruments

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

• Level 1: based on quoted prices in active markets;
• Level 2: based on inputs other than quoted prices as within level 1, that are either directly or indirectly observable;
• Level 3: based on inputs which are not based on observable market data.

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

31 March 2019 MUSD	Level 1	Level 2	Level 3
Assets
Underlift	10.9	–	–
Derivative instruments – non-current	–	0.5	–
Derivative instruments – current	–	23.5	–
	10.9	24.0	–
Liabilities
Overlift	4.3	–	–
Derivative instruments – non-current	–	78.9	–
Derivative instruments – current	–	20.0	–
	4.3	98.9	–

31 December 2018
MUSD	Level 1	Level 2	Level 3
Assets
Underlift	4.6	–	–
Derivative instruments – non-current	–	2.7	–
Derivative instruments – current	–	34.0	–
	4.6	36.7	–
Liabilities
Overlift	5.4	–	–
Derivative instruments – non-current	–	64.9	–
Derivative instruments – current	–	20.0	–
	5.4	84.9	–

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.

Parent Company Income Statement

	1 Jan 2019- 31 Mar 2019	1 Jan 2018- 31 Mar 2018	1 Jan 2018- 31 Dec 2018
Expressed in MSEK	3 months	3 months	12 months
Revenue	7.4	7.3	21.0
General and administration expenses	-42.3	-27.2	-180.9
Operating loss	-34.9	-19.9	-159.9
Net financial items
Finance income	4,638.8	4.7	1,818.1
Finance costs	-0.1	-0.2	-0.4
	4,638.7	4.5	1,817.7
Profit before tax	4,603.8	-15.4	1,657.8
Income tax	–	–	–
Net result	4,603.8	-15.4	1,657.8

Parent Company Comprehensive Income Statement

Expressed in MSEK	1 Jan 2019- 31 Mar 2019 3 months	1 Jan 2018- 31 Mar 2018 3 months	1 Jan 2018- 31 Dec 2018 12 months
Net result	4,603.8	-15.4	1,657.8
Other comprehensive income	–	–	–
Total comprehensive income	4,603.8	-15.4	1,657.8
Attributable to:
Shareholders of the Parent Company	4,603.8	-15.4	1,657.8
	4,603.8	-15.4	1,657.8

Parent Company Balance Sheet

Expressed in MSEK	31 March 2019	31 December 2018
ASSETS
Non-current assets
Shares in subsidiaries	55,118.9	55,118.9
Other tangible fixed assets	0.4	0.4
Total non-current assets	55,119.3	55,119.3
Current assets
Receivables	4,591.5	5.4
Cash and cash equivalents	34.9	29.5
Total current assets	4,626.4	34.9
TOTAL ASSETS	59,745.7	55,154.2
SHAREHOLDERS´EQUITY AND LIABILITIES
Shareholders´ equity including net result for the period	55,085.9	55,120.8
Non-current liabilities
Provisions	1.2	0.7
Total non-current liabilities	1.2	0.7
Current liabilities
Dividends	4,638.7	–
Other liabilities	19.9	32.7
Total current liabilities	4,658.6	32.7
Total liabilities	4,659.8	33.4
TOTAL EQUITY AND LIABILITIES	59,745.7	55,154.2

Parent Company Cash Flow Statement

Expressed in MSEK	1 Jan 2019- 31 Mar 2019 3 months	1 Jan 2018- 31 Mar 2018 3 months	1 Jan 2018- 31 Dec 2018 12 months
Cash flow from operations
Net result	4,603.8	-15.4	1,657.8
Adjustment for non-cash related items	-4,638.3	-4.3	-4.8
Changes in working capital	39.1	165.7	-159.9
Total cash flow from operations	4.6	146.0	1,493.1
Cash flow from investing
Investments in other fixed assets	–	–	-0.4
Total cash flow from investing	–	–	-0.4
Cash flow from financing
Dividends paid	–	–	-1,354.1
Purchase of own shares	–	-119.5	-119.5
Total cash flow from financing	–	-119.5	-1,473.6
Change in cash and cash equivalents	4.6	26.5	19.1
Cash and cash equivalents at the beginning of the period	29.5	4.8	4.8
Currency exchange difference in cash and cash equivalents	0.8	–	5.6
Cash and cash equivalents at the end of the period	34.9	31.3	29.5

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 2018	3.5	861.3	6,599.2	47,472.6	–	54,071.8	54,936.6
Total comprehensive income	–	–	–	-15.4	–	-15.4	-15.4
Transactions with owners
Purchase of own shares	–	–	-119.5	–	–	-119.5	-119.5
Total transactions with owners	–	–	-119.5	–	–	-119.5	-119.5
Balance at 31 March 2018	3.5	861.3	6,479.7	47,457.2	–	53,936.9	54,801.7
Total comprehensive income	–	–	–	1,673.2	–	1,673.2	1,673.2
Transactions with owners
Distributions	–	–	–	–	-1,354.1	-1,354.1	-1,354.1
Total transactions with owners	–	–	–	–	-1,354.1	-1,354.1	-1,354.1
Balance at 31 December 2018	3.5	861.3	6,479.7	49,130.4	-1,354.1	54,256.0	55,120.8
Transfer of prior year dividends	–	–	–	-1,354.1	1,354.1	–	–
Total comprehensive income	–	–	–	4,603.8	–	4,603.8	4,603.8
Transactions with owners
Distributions	–	–	–	–	-4,638.7	-4,638.7	-4,638.7
Total transactions with owners	–	–	–	–	-4,638.7	-4,638.7	-4,638.7
Balance at 31 March 2019	3.5	861.3	6,479.7	52,380.1	-4,638.7	54,221.1	55,085.9

Key Financial Data

Lundin Petroleum discloses alternative performance measures as part of its financial statements prepared in accordance with ESMA's (European Securities and Markets Authority) guidelines. Lundin Petroleum 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 Petroleum'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 2019- 31 Mar 2019 3 months	1 Jan 2018- 31 Mar 2018 3 months	1 Jan 2018- 31 Dec 2018 12 months
Revenue and other income	491.6	692.9	2,617.4
Operating cash flow	385.0	461.8	1,847.8
EBITDA	406.0	456.5	1,916.2
Free cash flow	95.8	171.8	663.0
Net result	54.9	228.8	222.1
Net debt	3,303.7	3,724.4	3,398.2
Data per share USD
Shareholders' equity per share	-2.45	-0.23	-1.13
Operating cash flow per share	1.14	1.36	5.46
Cash flow from operations per share	1.02	1.19	5.07
Free cash flow per share	0.28	0.51	1.96
Earnings per share	0.16	0.68	0.66
Earnings per share fully diluted	0.16	0.67	0.65
EBITDA per share	1.20	1.35	5.65
EBITDA per share – fully diluted	1.20	1.34	5.64
Dividend per share1	–	–	0.45
Number of shares issued at period end	340,386,445	340,386,445	340,386,445
Number of shares in circulation at period end	338,513,135	338,513,135	338,513,135
Weighted average number of shares for the period	338,513,135	338,833,988	338,592,250
Weighted average number of shares for the period fully diluted	339,165,735	339,752,964	339,513,634
Share price
Share price at period end in SEK	314.80	209.60	221.40
Share price at period end in USD2	34.01	25.11	24.72
Key ratios
Return on equity (%)3	–	–	–
Return on capital employed (%)	10	9	47
Net debt/equity ratio (%)3	–	–	–
Net debt/EBITDA ratio	1.8	2.3	1.8
Equity ratio (%)	-13	-1	-7
Share of risk capital (%)	23	25	29
Interest coverage ratio	15	12	17
Operating cash flow/interest ratio	23	17	21
Yield	–	–	2

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

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

3As the equity at 31 March 2019, 31 December 2018 and 31 March 2018 is negative, these ratios have not been calculated.

Relevant Reconciliations of Alternative Performance Measures

EBITDA MUSD	1 Jan 2019- 31 Mar 2019 3 months	1 Jan 2018- 31 Mar 2018 3 months	1 Jan 2018- 31 Dec 2018 12 months
Operating profit	267.2	337.6	1,402.4
Add: depletion of oil and gas properties	99.8	118.5	458.0
Add: exploration costs	37.3	-0.3	53.2
Add: depreciation of other tangible assets	1.7	0.7	2.6
EBITDA	406.0	456.5	1,916.2

Operating cash flow MUSD	1 Jan 2019- 31 Mar 2019 3 months	1 Jan 2018- 31 Mar 2018 3 months	1 Jan 2018- 31 Dec 2018 12 months
Revenue and other income	491.6	692.9	2,617.4
Minus: production costs	-40.1	-38.6	-145.4
Minus: purchase of crude oil from third parties	-40.1	-192.2	-533.8
Minus: current taxes	-26.4	-0.3	-90.4
Operating cash flow	385.0	461.8	1,847.8

Free cash flow MUSD	1 Jan 2019- 31 Mar 2019 3 months	1 Jan 2018- 31 Mar 2018 3 months	1 Jan 2018- 31 Dec 2018 12 months
Cash flows from operating activities	345.8	402.6	1,718.3
Minus: cash flows from investing activities	-250.0	-230.8	-1,055.3
Free cash flow	95.8	171.8	663.0

Net debt MUSD	1 Jan 2019- 31 Mar 2019 3 months	1 Jan 2018- 31 Mar 2018 3 months	1 Jan 2018- 31 Dec 2018 12 months
Bank loans	3,395.0	3,825.0	3,465.0
Minus: cash and cash equivalents	-91.3	-100.6	-66.8
Net debt	3,303.7	3,724.4	3,398.2

Key Ratio Definitions

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

EBITDA (Earnings Before Interest, Taxes, Depreciation and Amortisation): Operating 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.

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

Net debt: Bank loan less cash and cash equivalents.

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

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

Cash flow from operations per share: Cash flow from operating activities in accordance with the consolidated statement of cash flow divided by the weighted average number of shares for the period.

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

EBITDA per share fully diluted: EBITDA divided by the weighted average number of shares for the period after considering any dilution effect.

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

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.

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

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 non-interest bearing liabilities).

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

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

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

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

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

Operating cash flow/interest ratio: Revenue less production costs and less current taxes divided by the interest expense for the period.

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

Financial Information

The financial information relating to the three month period ended 31 March 2019 has not been subject to review by the auditors of the Company.

Stockholm, 2 May 2019

Alex Schneiter President and CEO

The Company will publish the following reports:

• The six month report (January June 2019) will be published on 31 July 2019.
• The nine month report (January September 2019) will be published on 31 October 2019.
• The year end report (January December 2019) will be published on 31 January 2020.

For further information, please contact:

VP Investor Relations Tel: +41 22 595 10 14 Investor Relations Officer Tel: +41 795 23 60 75

Edward Westropp Sofia Antunes Robert Eriksson Head of Media Communications Tel: +46 701 11 26 15 edward.westropp@lundin.ch sofia.antunes@lundin.ch robert.eriksson@lundin-petroleum.se

Definitions and abbreviations

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

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

Oil related terms and measurements

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

This information is information that Lundin Petroleum AB is required to make public pursuant to the EU Market Abuse Regulation and the Securities Markets Act. The information was submitted for publication, through the contact persons set out above, at 07.30 CET on 2 May 2019.

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 the Company's future performance, business prospects or opportunities. Forward-looking statements include, but are not limited to, statements with respect to estimates of reserves and/or resources, future production levels, future capital expenditures and their allocation to exploration and development activities, future drilling and other exploration and development activities. Ultimate recovery of reserves or resources are based on forecasts of future results, estimates of amounts not yet determinable and assumptions of management.

All statements other than statements of historical fact may be forward-looking statements. Statements concerning proven and probable reserves and resource estimates may also be deemed to constitute forward-looking statements and reflect conclusions that are based on certain assumptions that the reserves and resources can be economically exploited. Any statements that express or involve discussions with respect to predictions, expectations, beliefs, plans, projections, objectives, assumptions or future events or performance (often, but not always, using words or phrases such as "seek", "anticipate", "plan", "continue", "estimate", "expect", "may", "will", "project", "predict", "potential", "targeting", "intend", "could", "might", "should", "believe" and similar expressions) are not statements of historical fact and may be "forward-looking statements". Forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. No assurance can be given that these expectations and assumptions will prove to be correct and such forward-looking statements should not be relied upon. These statements speak only as on the date of the information and the Company 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 the Company'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 Petroleum AB (publ) Hovslagargatan 5 SE-111 48 Stockholm, Sweden T +46-8-440 54 50 W lundin-petroleum.com