Lundin Petroleum announces its 2018 budget and production guidance

Lundin Petroleum announces its 2018 budget and production guidance

23 January 2018

Lundin Petroleum AB (Lundin Petroleum) is pleased to announce its 2018 development, appraisal and exploration budget which totals USD 1.05 billion and represents an 11 percent decrease on 2017 capital expenditure. The production guidance for 2018 is between 74 to 82 thousand barrels of oil equivalent per day (Mboepd).

2018 Production Guidance
The average production in 2017 was 86.1 Mboepd, which was 15 percent above the mid-point of the original guidance and above the revised 2017 production guidance. Lundin Petroleum’s production guidance for 2018 is between 74 to 82 Mboepd with approximately 75 percent of the production contribution from the Edvard Grieg field.

Development Budget
The 2018 development expenditure is budgeted at USD 800 million. With respect to committed development projects, 2017 was the peak year of capital expenditure leading up to Johan Sverdrup first oil and 2018 development expenditure is 16 percent below the 2017 level.

1. Approximately 80 percent of the 2018 budgeted development expenditure relates to the non-operated Johan Sverdrup field (WI 22.6%) with 2018 being the peak year in terms of facilities installation for Phase 1 of the project. From inception and up to year end 2017, Lundin Petroleum’s net capital expenditure on Phase 1 amounted to USD 1.6 billion. The project is ahead of schedule with over 65 percent complete at year end 2017 and is on schedule for first oil in late 2019. The project is achieving significant cost reductions compared to the PDO estimate, with 25 percent savings to date excluding foreign exchange rate impacts, and further cost savings are anticipated with continued good progress on the project. The submission and approval of the PDO for Phase 2 of the project is scheduled for the second half of 2018 and the 2018 expenditure budget includes commencement of Phase 2 development activities including commitment to long lead equipment items.

2. The operated Edvard Grieg field (WI 65%) commenced production in late 2015 and the planned development drilling programme within the PDO has continued through 2016 and 2017 with 11 wells out of the planned 14 wells having been completed to date. The 2018 expenditure relates substantially to the drilling of the remaining three development wells with the jack-up drilling rig being demobilised in mid-2018 on completion of the planned programme.

3. Budgeted expenditure for the non-operated Alvheim and Volund fields (WI 15% and WI 35% respectively) involves the drilling of two infill wells one on each of the fields with drilling scheduled in the second half of 2018.

Appraisal Budget
The pre-tax appraisal budget for 2018 is USD 135 million.

The appraisal programme involves two operated appraisal wells in the Utsira High area in the Norwegian North Sea. One appraisal well at Luno II (WI 50%) which on success would lead to development planning and one horizontal appraisal well and testing at Rolvsnes (WI 50%), which has the potential to de-risk the significant potential in the larger basement high area. Both Luno II and Rolvsnes are possible subsea tie-back development opportunities to the Edvard Grieg facilities. Additionally, an extended well test will be conducted at the Alta oil discovery (WI 40%) in the southern Barents Sea, which involves drilling of a horizontal production well and producing to a tanker for up to two months, to reduce the uncertainty around the recovery mechanism and provide the basis for development studies.

The 2018 appraisal budget also includes expenditure on front end engineering design (FEED) and PDO studies for Johan Sverdrup Phase 2.

Exploration Budget
The pre-tax exploration budget for 2018 is USD 115 million with a total of eight planned exploration wells.

Four wells are planned to be drilled in the southern Barents Sea. One well on the Svanefjell prospect in PL659 (WI 20%) and one well on the Shenzhou prospect in PL722 (WI 20%). The remaining two wells will be drilled in the southeastern area on licences that were awarded in the 23rd licensing round, with one well targeting the deeper horizons of the Korpfjell prospect in PL859 (WI 15%) and one well targeting the shallow horizons of the large Gjøkåsen prospect in PL857 (WI 20%).

Four wells are planned to be drilled in the Norwegian North Sea on the Lille Prinsen prospect in PL167 (WI 20%) in the Utsira High, on the Frosk prospect in PL340 (WI 15%) in the Alvheim area which is currently drilling, on the Rungne prospect in PL825 (WI 30%) and on the Mandal High prospect in PL860 (WI 40%) where the Company has recently acquired a position through a series of transactions. The acquisition of PL825 and PL860 are subject to certain government and seller bank approvals.

 

Lundin Petroleum announces reserves and contingent resources update

Lundin Petroleum announces reserves and contingent resources update

22 January 2018

Lundin Petroleum AB (Lundin Petroleum) is pleased to announce that as at 31 December 2017, its proved plus probable net reserves (2P reserves) are 726 million barrels of oil equivalent (MMboe), its proved plus probable plus possible net reserves (3P reserves) are 895 MMboe and its best estimate net contingent resources (contingent resources) are 203 MMboe. The Edvard Grieg field, Lundin Petroleum’s main producing asset, represents an increase of 51 MMboe gross 2P reserves from year end 2016, excluding production, and a 47 percent increase in best estimate ultimate recovery from the original PDO.

Reserves
Lundin Petroleum’s 2P reserves as at 31 December 2017 are 726.3 MMboe1,2 and reflect a positive revision of 45.8 MMboe, excluding sales. The 3P reserves as at 31 December 2017 are 895.5 MMboe1,2 and reflect a positive revision of 31.5 MMboe, excluding sales.

 

2P Reserves3P Reserves
End 2016 714.1898.1
-Produced3-31.9-31.9
-Sales/+ Acquisitions-1.7-2.2
+Revisions+45.8+31.5
End 2017726.3895.5
Reserves replacement ratio4144%99%

 

The main reason for the increase in reserves relates to Lundin Petroleum’s two main assets, the Edvard Grieg and Johan Sverdrup fields, both located on the Utsira High in the Norwegian North Sea. The reserves upgrade on Edvard Grieg is driven by the drilling results and production performance to date which indicate more oil-in-place and with a greater proportion of the oil-in-place in the high quality high recovery factor sands as compared to the lower quality conglomerate reservoir. The best estimate gross ultimate recovery from Edvard Grieg as at end 2017 is 274 MMboe, which is cumulative production to end 20175 plus 2P reserves. This represents an increase of 51 MMboe from year end 2016 and a 47 percent increase from the original PDO. Additionally, the high estimate gross ultimate recovery from Edvard Grieg as at end 2017 is 337 MMboe, which is cumulative production to end 20175 plus 3P reserves. This represents an increase of 27 MMboe from year end 2016. Further contingent resources are identified associated with infill drilling opportunities.

The upgrade of reserves in the Johan Sverdrup field are consistent with the upgrade announced by Statoil during 2017 and reflects positive drilling results and optimisation of the reservoir development plan. Further reserves increases have been attributed to the Alvheim and Volund fields. Oil accounts for 93 percent of Lundin Petroleum’s 2P reserves.

The reserves are based upon a third party independent audit conducted by ERCE. The reserves have been calculated using 2007 Petroleum Resource Management System (SPE PRMS), Guidelines of the Society of Petroleum Engineers (SPE), World Petroleum Congress (WPC), American Association of Petroleum Geologists (AAPG) and Society of Petroleum Evaluation Engineers (SPEE).

1 BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf : 1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

2 The reserves were calculated using a nominal Brent oil price of USD 58 per barrel in 2018, 61 in 2019, 66 in 2020, 71 in 2021, 75 in 2022, 77 in 2023, 78 in 2024, 80 in 2025 and increasing by 2 percent per year thereafter.

3 As per industry standards the reserves replacement ratio is defined as the ratio of reserve additions to production during the year, excluding sales and acquisitions.

4 Reserves are measured in saleable quantities (saleable oil, natural gas liquids and dry gas converted to oil equivalents), which may differ from production volumes provided in corporate reports which are given in wellhead production quantities (oil and rich gas converted to oil equivalents).

5 Gross production to 31 December 2017 is 66.1 MMboe.

 

Contingent resources
Lundin Petroleum’s net contingent resources as at 31 December 2017 are 203 MMboe6. Contingent resources have been added associated with infill drilling opportunities at the Edvard Grieg field and from the Filicudi oil discovery in the southern Barents Sea. At the Alvheim area contingent resources have been transferred to reserves associated with finalising infill drilling plans for 2018. Contingent resources have been reduced at the Gohta oil discovery in the southern Barents Sea due to the results from the appraisal well drilled in 2017 and have also been reduced at the adjacent Alta oil discovery following a detailed review of all the wells completed in 2016 and 2017. Based on this, the combined gross contingent resource range for the Alta and Gohta discoveries is between 115 and 390 MMboe. An extended well test will be conducted at Alta in 2018 to reduce reservoir uncertainty and provide the basis for development studies.

6 This volume is a combination of independently audited and management estimates. Contingent resources for the Edvard Grieg, Alvheim area and Johan Sverdrup assets are based on a third party independent audit conducted by ERCE and for the other assets are estimated by Lundin Petroleum’s management.

Update on fourth quarter 2017 financial results

Update on fourth quarter 2017 financial results

17 January 2018

Lundin Petroleum AB (Lundin Petroleum) will expense pre-tax exploration costs of approximately MUSD 31 and recognise a net foreign exchange loss of approximately MUSD 69 as well as an after tax loss on sale of assets of MUSD 15 for the fourth quarter of 2017.

The profitability for the fourth quarter of 2017 will be impacted by certain expensed exploration costs, a loss on sale of assets, as well as a net foreign currency exchange loss mainly related to the revaluation of loan balances. These items are largely non-cash and will have no impact on operating cash flow or EBITDA.

Exploration Costs
During the fourth quarter of 2017, Lundin Petroleum will incur pre-tax exploration costs of approximately MUSD 31 which will be charged to the income statement and offset by a tax credit of approximately MUSD 24. The exploration costs are mainly related to the non-commercial gas discovery on the Hufsa prospect and the dry well on the Hurri prospect, both located in PL533.

Loss on Sale of Assets
The previously announced transaction in relation to the divestment of a 39 percent working interest in the Brynhild field to CapeOmega was completed on 30 November 2017. Lundin Petroleum has previously announced that on completion of the transaction a net loss on sale of assets would be recorded as a result of the accounting for income taxes in accordance with IFRS. Consequently an after tax loss of MUSD 15 will be charged to the income statement for the fourth quarter 2017.

Net debt and Foreign Exchange Loss
The net debt position of Lundin Petroleum at 31 December 2017 amounted to USD 3.9 billion resulting in available liquidity of USD 1.1 billion within its USD 5.0 billion reserve-based lending facility.

Lundin Petroleum will recognise a net foreign exchange loss of approximately MUSD 69 for the fourth quarter of 2017. The Norwegian Krone weakened against the US Dollar by approximately 3 percent and the Euro strengthened against the US Dollar by approximately 2 percent during the fourth quarter of 2017. The foreign exchange loss mainly relates to the revaluation of loan balances at the prevailing exchange rates at the balance sheet date.

 

APA 2017 – 14 licences awarded in the Norwegian licensing round

APA 2017 – 14 licences awarded in the Norwegian licensing round

16 January 2018

Lundin Petroleum AB (Lundin Petroleum) is pleased to announce that its wholly owned subsidiary Lundin Norway AS (Lundin Norway) has been awarded a total of 14 exploration licence interests in the 2017 Norwegian licensing round (Awards in Predefined Areas, APA).

The record-high award includes six licences in the North Sea, four licences in the Norwegian Sea and four licences in the southern Barents Sea. Six of the awarded licences will be operated by Lundin Norway.

The licence interests are detailed below and a map is included in the attachment.

Licence Lundin Norway licence interest
PL904 (Blocks 2/9, 3/7):20% – North Sea
PL167C (Block 16/1):20% – North Sea
PL914S (Ivar Aasen unit)(Block 16/1):1.385% – North Sea
PL916 (Blocks 16/2, 25/11):20% – North Sea
PL917 (Blocks 25/7, 10):20% – North Sea
PL919 (Block 25/4):15% – North Sea
PL934 (Blocks 6307/2, 5)*:40% – Norwegian Sea
PL935 (Block 6306/3):20% – Norwegian Sea
PL936 (Blocks 6306/2, 5):30% – Norwegian Sea
PL886B (Blocks 6307/1, 4)*:40% – Norwegian Sea
PL950 (Blocks 7020/1, 2, 7120/11)*:50% – Southern Barents Sea
PL952 (Blocks 7124/5,6,8,9, 7125/4,5,6,7)*:60% – Southern Barents Sea
PL954 (Blocks 7121/1,2,3, 7221/10, 11)*:40% – Southern Barents Sea
PL533B (Block 7219/11)*:35% – Southern Barents Sea
*operator Lundin Norway

 

Exploration well completed on the Hurri prospect in the southern Barents Sea

Exploration well completed on the Hurri prospect in the southern Barents Sea

10 January 2018

Lundin Petroleum AB (Lundin Petroleum) announces that its wholly owned subsidiary Lundin Norway AS (Lundin Norway) has completed the drilling of the Hurri exploration well 7219/12-3S located in PL533 in the southern Barents Sea. The well was dry.

The main objectives of the well were to test the reservoir properties and hydrocarbon potential of the Upper Jurassic Hekkingen formation and Middle Jurassic Stø formation.

The well encountered no reservoir development in the Hekkingen formation and good reservoir in the Stø formation but with no indications of hydrocarbons. Extensive data acquisition and sampling were carried out.

The well was drilled using the semi-submersible drilling rig Leiv Eiriksson which after completion of operations on the Hurri well will proceed to abandon the Filicudi discovery well, also located in PL533.

Lundin Norway is the operator of PL533 with a 35 percent working interest. The partners are Aker BP with 35 percent and DEA Norge with 30 percent.

 

Lundin Petroleum spuds exploration well on the Hurri prospect in the southern Barents Sea

Lundin Petroleum spuds exploration well on the Hurri prospect in the southern Barents Sea

4 December 2017

Lundin Petroleum AB (Lundin Petroleum) is pleased to announce that its wholly owned subsidiary Lundin Norway AS (Lundin Norway) has commenced drilling of exploration well 7219/12-3 on the Hurri prospect in PL533 in the southern Barents Sea.

The well is located in PL533, approximately 2 km southwest of the Filicudi oil discovery and south of the Statoil operated Johan Castberg oil discovery.

The main objective of the well is to test the reservoir properties and hydrocarbon potential of the Jurassic Hekkingen and Stø formations. The Hurri prospect is estimated to contain gross unrisked prospective resources of 218 MMboe.

The well will be drilled with the semi-submersible drilling rig Leiv Eiriksson and is expected to take approximately 50 days.

Lundin Norway is the operator of PL533 with a 35 percent working interest. The partners are Aker BP with 35 percent and DEA Norge with 30 percent.

Non-commercial gas discovery on the Hufsa prospect in the southern Barents Sea

Non-commercial gas discovery on the Hufsa prospect in the southern Barents Sea

22 November 2017

Lundin Petroleum AB (Lundin Petroleum) announces that its wholly owned subsidiary Lundin Norway AS (Lundin Norway) has completed the drilling of exploration well 7219/12-2 on the Hufsa prospect in PL533 in the southern Barents Sea. A non-commercial gas discovery was made in the main well while the sidetrack was dry.

The main objective of the well was to prove oil in Jurassic and Triassic sandstone reservoirs.

The main well 7219/12-2S encountered a gross 22 metres gas column while no hydrocarbons were encountered in the sidetrack 7219/12-2A. Extensive data acquisition and sampling have been carried out, including coring, logging and sampling of gas from the wireline tools.

The well was drilled with the semi-submersible drilling rig Leiv Eiriksson which after completion will proceed to drill the Hurri prospect, also located in PL533.

Lundin Norway is the operator of PL533 with a 35 percent working interest. The partners are Aker BP with 35 percent and DEA Norge with 30 percent.

Report for the nine months ended 30 September 2017

Report for the nine months ended 30 September 2017

1 November 2017

Lundin Petroleum delivers strong results for the first nine months 2017. High production levels at continuing low cash operating costs and a higher realised oil price resulted in a significant increase in revenue, EBITDA and operating cash flow compared to the same period in 2016.

Third quarter highlights
·   Record quarter EBITDA and operating cash flow driven by high production, low costs and higher oil price.
·   Quarter production above guidance with full year production expected at or above the higher end of the 80-85 Mboepd guidance range.
·   Continued low cash operating costs, forecast to be below the full year guidance of USD 4.60 per barrel.
·   Positive update for the Johan Sverdrup project with 60 percent of Phase 1 complete and further cost reductions.
·   2017 full year development expenditure guidance reduced from MUSD 1,085 to MUSD 980.

Financial summary

Continuing operations
——————————–
Jan 2017-
30 Sep 2017
9 months

—————-
1 Jul 2017-
30 Sep 2017
3 months
—————-
1 Jan 2016-
30 Sep 2016
9 months
————–
1 Jul 2016-
30 Sep 2016
3 months
————–
1 Jan 2016-
31 Dec 2016
12 months
————–
Production in Mboepd87.189.255.367.559.3
Revenue in MUSD1,403.3  517.2623.8269.0950.0
EBITDA in MUSD1,071.7  382.4475.8215.3  752.5
Operating cash flow in MUSD1,095.5  389.6557.0243.0857.9
Net result in MUSD431.8227.0263.4  169.8-399.3
Earnings/share in USD1   1.280.670.830.52-0.79
Earnings/share fully diluted in USD11.280.670.82  0.51-0.79
Net debt4,024.04,024.04,307.14,307.14,075.5

The numbers included in the table above are based on continuing operations (including 2016 comparatives)
1 Based on net result attributable to shareholders of the Parent Company

Comments from Alex Schneiter, President and CEO of Lundin Petroleum:
“Lundin Petroleum has delivered another great quarter with record operating cash flow and EBITDA, driven by continued strong production performance from our core assets. With these excellent results we are firmly on track to meet or exceed the higher end of the full year production guidance and our total cash operating cost is forecast to be below the full year guidance of USD 4.60 per barrel.

The Johan Sverdrup development continues to improve both in terms of project completion and further cost reductions. Phase 1 is now 60 percent complete with over 40 million man-hours worked to date. Costs are about 25 percent lower for Phase 1 and 50 percent lower for Phase 2 compared to PDO submission and I believe we will see further savings as the project progresses.

We remain optimistic about the significant exploration potential in the southern Barents Sea, despite recent disappointing results. This is a new frontier area where more exploration is needed to understand and unlock its full potential. We are drilling two further exploration wells on the Filicudi trend before the end of this year (Hufsa and Hurri) and we will soon announce our 2018 drilling programme, targeting more prospects in the southern Barents Sea, the Utsira High and the Mandal High.

Oil prices strengthened in the third quarter on the back of healthy demand growth, decreasing oil inventories and the prospect of an extended OPEC quota. I believe we will see further upward pressure on the oil price as the supply market tightens following the significant under investments in our industry in the last few years. Lundin Petroleum has never been better positioned to benefit from the current oil market recovery with production due to double by late 2022 and with record low cash operating costs below USD 5 per barrel for the next decade. With a strong focus on cost discipline, operating efficiency and high HSE standards, Lundin Petroleum will continue to pursue an exciting organic growth strategy.”

Webcast presentation
Listen to Alex Schneiter, President and CEO, and Teitur Poulsen, CFO, commenting on the report at a live webcast held on Wednesday 1 November 2017 at 09.00 CET.

Follow the presentation live on www.lundin-petroleum.com or by dialling in on the following telephone numbers:
Sweden: +46 8 519 993 55
Norway: +47 23 500 211
UK/International: +44 203 194 05 50
International Toll Free: +1 855 269 26 05

Link to webcast

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9 month report 2017
01.11.2017, 747.61 KB

Lundin Petroleum to release third quarter report 2017 on 1 November 2017

Lundin Petroleum to release third quarter report 2017 on 1 November 2017

25 October 2017

Lundin Petroleum’s financial report for the third quarter 2017 will be published on Wednesday 1 November at 07.30 CET, followed by a live webcast at 9.00 CET.

Listen to Alex Schneiter, President and CEO, and Teitur Poulsen, CFO, commenting on the report and the latest developments in Lundin Petroleum.

Follow the presentation live on www.lundin-petroleum.com.

You can also dial in to listen to the presentation on the following telephone numbers:

Sweden:        +46 8 519 993 55
Norway:        +47 23 500 211
UK/International:     +44 203 194 05 50
International Toll Free:     +1 855 269 26 05

Link to webcast