Lundin Petroleum : Year End Report 2018 (regulatory)

Q4

Highlights

• • Strong financial performance with record free cash flow generation of MUSD 663

• • Board of Directors propose a dividend for 2018 of USD 1.48 per share, corresponding to MUSD 500

• • Production of 81.1 Mboepd at upper end of guidance for the year, supported by excellent performance from Edvard Grieg

• • Operating cost of USD 3.66 per barrel, below the updated guidance for the year

• • Johan Sverdrup project on schedule with approximately 85 percent of Phase 1 completed, start-up anticipated in November 2019

• • Increase of proved plus probable reserves to 745 MMboe with a reserves replacement ratio of 163 percent

Financial summary

1 Jan 2017-	1 Oct 2017-
31 Dec 2017	31 Dec 2017
12 months	3 months
Production in Mboepd	86.1	83.1
Revenue and other income in MUSD	1,997.0	593.7
Operating cash flow in MUSD	1,530.0	434.5
EBITDA in MUSD	1,501.5	429.8
Free cash flow in MUSD	203.7	160.6
Net result in MUSD	380.9	-50.9
Earnings/share in USD1	1.13	-0.15
Net debt	3,883.6	3,883.6
The numbers included in the table above for 2017 are based on continuing operations.
1 Based on net result attributable to shareholders of the Parent Company.
Comment from Alex Schneiter, President and CEO of Lundin Petroleum:

1 Jan 2018-	1 Oct 2018-
31 Dec 2018 12 months	31 Dec 2018 3 months
81.1 2,617.4 1,847.8 1,916.2 663.0 222.1 0.66 3,398.2	82.1 611.0 419.1 448.5 173.3 -105.3 -0.31 3,398.2

"2018 proved to be a standout year across all areas of our business, with excellent performance from our producing assets, strong financial results and success with the drill bit. For the fifth consecutive year, we have ended the period having more than replaced our produced barrels with reserves.

"Buoyed by stronger commodity prices, operating cost below guidance and very strong production efficiency, we have delivered EBITDA in excess of USD 1.9 billion and also record high free cash flow of USD 663 million for the year. I am also very pleased to announce that in the light of this and our strong financial outlook over the next decade, the Board of Directors has adopted an updated dividend policy which will be sustainable and will deliver an annual cash dividend of USD 500 million, which we aim to grow further as the business continues to grow.

"The key producing assets Edvard Grieg and Alvheim have continued to perform above expectations. Production efficiency at Edvard Grieg was 98 percent for the year and reservoir performance continues to exceed expectations with a significantly slower build-up of water production than anticipated, leading to a six month extension of plateau production to mid-2020. This has been achieved while maintaining an industry leading, low carbon intensity per produced barrel, at about one quarter of the industry world average. Edvard Grieg really is a world-class asset, which epitomises what can be achieved when excellent reservoir management is coupled with new, modern facilities, which are able to utilise innovative, practical technologies and practices.

"The giant Johan Sverdrup field is now less than a year away from start-up and 2018 was a critical year of project delivery. Phase 1 is now approximately 85 percent complete and all four steel jackets have been successfully installed offshore, as well as the topsides for the drilling platform and the riser platform. I am also pleased that during the year the key metrics for the project were upgraded, lowering the total capital expenditure guidance, increasing reserves, confirming expected Phase 1 first oil to be in November 2019 and submitting the Phase 2 PDO.

"The 2018 exploration and appraisal campaign was one of our busiest and we enjoyed significant success with new discoveries made near our core areas on the Utsira High and the Alvheim area. We matured our appraisal opportunities further towards development and now have seven potential new projects in the pipeline. At Rolvsnes and Alta, we were able to de-risk the commercial potential of these unique discoveries through test production. Complementing our successful organic growth strategy, we were able to execute important additions to our Utsira High position. At Luno II we increased our working interest to 65 percent to bring commercial and operational alignment with the Edvard Grieg partnership and we recently announced the strategic acquisition of Lime Petroleum's interests in the licences containing the Rolvsnes oil discovery and Goddo prospect, increasing our working interest in this area that has potential of over 250 MMboe gross resources.

"Looking forward, 2019 will be one of the most significant years in Lundin Petroleum's history, which started with a record award in the 2018 APA licensing round, growing our acreage position by about 70 percent since year-end 2017. The giant Johan Sverdrup field is set to start production in November and we will deliver our busiest exploration and appraisal programme to date, targeting over 750 MMboe of additional net resources. I would like to thank all of our stakeholders for their support in 2018 and very much look forward to another period of continued delivery and 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 atwww.lundin-petroleum.com

For definitions and abbreviations, see pages 30 and 32.

OPERATIONAL REVIEW

All the reported numbers and updates in the operational review relate to the financial year ended 31 December 2018 unless otherwise specified.

Norway

Reserves and Resources

Lundin Petroleum has 745.4 million barrels of oil equivalent (MMboe) of proved plus probable net reserves and 900.9 MMboe of proved plus probable plus possible net reserves as at 31 December 2018 as certified by an independent third party. Lundin Petroleum also has discovered oil and gas resources which classify as contingent resources and are not yet classified as reserves. The best estimate contingent resources net to Lundin Petroleum amounted to 225 MMboe as at 31 December 2018. The proved plus probable reserves replacement ratio for 2018 was 163 percent.

Production

Production was 81.1 thousand barrels of oil equivalent per day (Mboepd) (compared to 86.1 Mboepd for 2017) which was at the upper end of the updated guidance for the year of between 78 and 82 Mboepd and 4 percent above the mid-point of the original production guidance of between 74 and 82 Mboepd. This performance is due to strong facilities and reservoir performance at both the Edvard Grieg field and the Alvheim area.

Operating cost, including netting off tariff income, was USD 3.66 per barrel which was below the revised full year guidance of less than USD 3.80 per barrel and 12 percent below the original guidance of USD 4.15 per barrel. This performance is due to a combination of reduced costs, increased production volumes and the termination of production from the Brynhild field during the year.

1 Jan 2017-	1 Oct 2017-
Production	31 Dec 2017	31 Dec 2017
in Mboepd	12 months	3 months
Norway
Crude oil	77.6	74.6
Gas
	8.5	8.5
Total production
	86.1	83.1
1 Jan 2017-	1 Oct 2017-
Production	31 Dec 2017	31 Dec 2017
in Mboepd	WI1	12 months	3 months
Edvard Grieg	65%	66.7	62.7
Ivar Aasen	1.385%	0.7	0.9
Alvheim	15%	12.4	9.8
Volund	35%	3.9	8.7
Bøyla	15%	1.1	0.9
Brynhild	51%2	1.2	-
Gaupe	40%	0.2	0.2
86.1	83.1
1 Lundin Petroleum's working interest (WI).
2 WI 90% up to 30 November 2017.

1 Jan 2018-	1 Oct 2018-
31 Dec 2018 12 months	31 Dec 2018 3 months
71.9 9.2	73.5 8.6
81.1	82.1

1 Jan 2018-	1 Oct 2018-
31 Dec 2018 12 months	31 Dec 2018 3 months
63.6 0.9	65.6 0.8
9.3	10.1
6.5	5.2
0.7	0.4
0.0	-
0.1	-
81.1	82.1

Production from the Edvard Grieg field was above forecast, supported by continued strong production efficiency at 98 percent. During the fourth quarter 2018, Edvard Grieg production benefitted from additional facility capacity due to a cut back of Ivar Aasen production during maintenance of one of the Edvard Grieg turbine generators. The PDO development drilling programme was completed in the middle of the year with all development well results in line with or better than prognosis and the overall drilling programme was completed below budget. Edvard Grieg reservoir performance continues to exceed expectations with significantly slower build-up of water production than anticipated, leading to around a six month extension of plateau production to mid-2020. The 4D seismic survey that has been acquired over the Edvard Grieg field as part of the reservoir monitoring programme, indicates that the water injection flood front is further away from the main production wells than predicted by the current reservoir models. This information is still under review and has not been incorporated into the reservoir models used to support the year end 2018 reserves estimate. An infill drilling programme is being planned at Edvard Grieg commencing in 2020 and sanction of this project is anticipated during 2019. Operating cost for the Edvard Grieg field, including netting off tariff income, was USD 3.95 per barrel.

Production from the Ivar Aasen field was slightly below forecast, impacted in the fourth quarter 2018 by the Edvard Grieg power system maintenance. During the second quarter 2018, two new water injection wells were successfully drilled to improve pressure support to the eastern area of the field.

Production from the Alvheim area, consisting of the Alvheim, Volund and the Bøyla fields, was slightly ahead of forecast, supported by the strong reservoir performance and continued strong production efficiency for the Alvheim FPSO of 97 percent. The results of the infill well in the Kameleon area of the Alvheim field were in line with expectations and the well was brought on line ahead of schedule during the fourth quarter 2018. Combined with the two infill wells in the Boa area of the field, brought on line at the beginning of the year, this largely offsets the natural production decline from the area. Operating cost for the Alvheim area was USD 4.96 per barrel.

For the Brynhild field, the decision has been taken to permanently shut-in production and work on a cessation plan is ongoing, which will be submitted in due course to the authorities for approval. The remaining book value for the field was written off at year end 2017.

Despite no remaining reserves being attributable to the Gaupe field, the field has produced intermittently subject to favourable economic conditions. As it is no longer economic to continue with Gaupe field production, the decision was taken in October 2018 to cease production from the field.

Development

Field

WI Operator PDO ApprovalEstimated gross Production start reserves expectedExpected gross plateau production

Johan Sverdrup

22.6% Equinor August 2015

2.2 - 3.2 Bn boe November 2019

660 Mbopd

Johan Sverdrup

Phase 1 of the Johan Sverdrup project is on schedule with approximately 85 percent completed. With the good project progress the expected schedule for Phase 1 first oil is November 2019.

2018 was a key installation year for Phase 1 of the project and the programme for the year was completed as planned. All of the four steel jackets have now been successfully installed offshore, as well as the topsides for the drilling platform and the riser platform. The power from shore cable has been installed and power supply from shore to the offshore facilities commenced in October 2018. Installation of the oil and gas export pipelines have been completed. Two accommodation units are located offshore and at peak approximately 800 personnel have been working on the hook-up of the installed offshore facilities, which is progressing on schedule.

Of the last two remaining topsides, the process platform topside sailed away from the Samsung Heavy Industries yard in South Korea in December 2018 and is expected to arrive at the Kværner Stord yard in Norway in February 2019. Construction of the living quarters topside at the Kværner yard has been completed and both these topsides are on schedule for installation in spring 2019.

Pre-drilling operations were completed significantly ahead of schedule with a total of eight pre-drilled producers and twelve water injectors completed. In December 2018, the drilling platform commenced tie-back operations on the eight pre-drilled production wells.

The latest capital expenditure estimate for Phase 1 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 gross production capacity of Phase 1 is estimated at 440 Mbopd.

The Phase 2 PDO was submitted to the Norwegian Ministry of Petroleum and Energy in August 2018, with Phase 2 first oil scheduled in the fourth quarter 2022. Phase 2 involves an additional processing platform bridge linked to the Phase 1 field centre, additional subsea facilities to allow the 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. These additional facilities will take the gross plateau production capacity to 660 Mbopd. With the inclusion of WAG, the gross resource range has been further increased to between 2.2 and 3.2 billion boe.

The Phase 2 capital expenditure is estimated at gross NOK 41 billion (nominal), which represents over a 50 percent saving from the original estimate in the phase 1 PDO, and is due to a combination of market conditions and optimisation of the Phase 2 facilities. The major topsides contracts and the jacket contract for the Phase 2 facilities have been awarded and detailed engineering is progressing to plan. Full field breakeven oil price is estimated at below 20 USD per barrel.

Appraisal

2018 appraisal well programme

Licence	Operator	WI	Well	Spud Date	Status
PL359	Lundin Norway	65%	Luno II	February 2018	Completed March 2018
PL338C	Lundin Norway	50%	Rolvsnes	April 2018	Completed August 2018
PL609	Lundin Norway	40%	Alta	April 2018	Completed September 2018
PL203	Aker BP	15%	Gekko	September 2018	Completed October 2018

All four wells in the 2018 appraisal drilling and testing programme were successful. Combined with two new exploration discoveries that were made during 2018, means that Lundin Petroleum has six potential projects being moved through the appraisal phase. These positive results contributed to increasing the booked contingent resources at year end 2018.

The Luno II appraisal well in PL359 on the Utsira High was successfully completed in March 2018 and encountered a gross oil column of 22 metres in Triassic sandstones with very good reservoir quality, which was significantly better than expected. Following the positive well results, the gross resource range for the Luno II discovery has been increased to between 40 and 100 MMboe. The development concept for Luno II is a subsea tie-back to the nearby Edvard Grieg platform. Phase 1 of the Luno II development project is expected to be sanctioned and the PDO submitted in the first quarter of 2019. To create commercial and operational alignment between the Edvard Grieg and Luno II partnerships, Lundin Petroleum has acquired Equinor's 15 percent interest in Luno II, increasing the working interest to 65 percent.

Appraisal drilling and production testing operations on the Rolvsnes basement oil discovery in PL338C in the Utsira High area of the North Sea were completed in August 2018. The horizontal well confirmed good productivity from fractured and weathered basement reservoirs and achieved a constrained production rate of 7,000 bopd. The successful well and testing operations have led to a substantial increase in gross resources for Rolvsnes to between 14 and 78 MMboe from previously 3 to 16 MMboe. The long-term production behavior from this reservoir needs to be understood better and the next step is to conduct an extended well test via a subsea tie-back of the suspended appraisal well to the Edvard Grieg platform. It is expected that the extended well test will be sanctioned in the first quarter of 2019 and implementation will be in parallel with the Luno II development project. The positive well result at Rolvsnes de-risks the similar on-trend prospectivity on the adjacent PL815 licence where an exploration well will be drilled on the Goddo prospect in 2019. The combined Rolvsnes and Goddo prospective area is estimated to contain gross potential resources of more than 250 MMboe.

The extended production testing on the Alta discovery in the southern Barents Sea was successfully completed in September 2018. The well was produced over a period of about two months with a maximum production rate of 18,000 bopd constrained by the surface facilities and with a total of approximately 660,000 barrels of oil produced to a tanker. The results were better than expected, demonstrating excellent reservoir productivity and connectivity to a large volume of oil. The large amount of new information from the positive results from the Alta extended production test and latest generation 3D seismic survey (Topseis) over the entire Alta and Gohta area is still being evaluated. The contingent resources for the Alta and Gohta discoveries are therefore unchanged from year end 2017 and will be updated during 2019 when the future appraisal plans for the area is defined and all the additional data has been processed.

The Gekko appraisal well located to the southeast of the Alvheim field was successfully completed in October 2018. The objective of the two branch well was to test the potential for improved reservoir quality away from the Gekko discovery well and determine the thickness of the oil column. Both well branches encountered good quality Heimdal sands with an approximately 6 metre oil rim below gas. Following the positive well results, the gross resource range for the Gekko discovery is between 28 and 52 MMboe. Options for the economic development of Gekko are being assessed.

Exploration

2018 exploration well programme

Licence	Operator	WI	Well	Spud Date	Result
PL340	Aker BP	15%	Frosk	January 2018	Oil discovery
PL167	Equinor	20%	Lille Prinsen	April 2018	Oil discovery
PL659	Aker BP	20%	Svanefjell	May 2018	Minor gas discovery
PL830	Lundin Norway	40%	Silfari	October 2018	Dry
PL860	MOL	40%	Driva/Oppdal	November 2018	Dry
PL857	Equinor	20%	Gjøkåsen Shallow	December 2018	Ongoing
PL857	Equinor	20%	Gjøkåsen Deep	January 2019	Ongoing
PL767	Lundin Norway	50%	Pointer/Setter	January 2019	Ongoing
PL869	AkerBP	20%	Froskelår Main	January 2019	Ongoing

The 2018 exploration drilling programme was impacted by changing rig schedules and priorities, which resulted in a number of wells moving into 2019. Five exploration wells were completed in 2018 resulting in two potential commercial discoveries, Frosk and Lille Prinsen. Exploration and appraisal expenditure in 2018 was MUSD 311.

In February 2018, the Frosk prospect in the North Sea, located northwest of the Bøyla field, proved an oil discovery. The discovery is estimated to contain gross resources of between 30 and 60 MMboe, which is significantly more than the pre-drill estimates and has a positive impact on the assessment of further exploration potential in the area. Two follow-up wells on the Froskelår Main and Rumpetroll prospects in the adjacent PL869 will be drilled in the first half of 2019, with the first of these wells currently ongoing. Additionally, a production test well on the Frosk discovery, to be tied into the Bøyla subsea facilities, will be drilled in the first half of 2019.

In May 2018, the Svanefjell prospect in PL659 in the southern Barents Sea proved a minor, non-commercial gas discovery.

In June 2018, the Lille Prinsen prospect in the North Sea, located northeast of the Ivar Aasen field, proved an oil discovery. The discovery is estimated to contain gross resources of between 15 and 35 MMboe and with significant appraisal upside potential of over 100 MMboe. It is expected that Lille Prinsen will be economic to develop and an appraisal well is planned for 2019.