Interim / Quarterly Report • Aug 5, 2015
Interim / Quarterly Report
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Lundin Petroleum AB (publ) company registration number 556610-8055
| 1 Jan 2015– 30 Jun 2015 6 months |
1 Apr 2015– 30 Jun 2015 3 months |
1 Jan 2014– 30 Jun 2014 6 months |
1 Apr 2014– 30 Jun 2014 3 months |
1 Jan 2014– 31 Dec 2014 12 months |
|
|---|---|---|---|---|---|
| Production in Mboepd1 | 27.4 | 28.9 | 26.0 | 25.4 | 23.8 |
| Revenue in MUSD | 279.1 | 157.8 | 460.8 | 225.4 | 785.2 |
| Net result in MUSD | -171.0 | 59.9 | 0.8 | -2.4 | -431.9 |
| Net result attributable to shareholders of the Parent Company in MUSD |
-168.8 | 61.1 | 3.2 | -1.2 | -427.2 |
| Earnings/share in USD2 | -0.55 | 0.20 | 0.01 | 0.00 | -1.38 |
| Earnings/share fully diluted in USD2 | -0.54 | 0.20 | 0.01 | 0.00 | -1.38 |
| EBITDA in MUSD | 192.4 | 106.5 | 349.3 | 171.5 | 671.3 |
| Operating cash flow in MUSD | 347.3 | 191.6 | 497.0 | 241.0 | 1,138.5 |
1 Excluding production from Russian onshore assets following the sale of the assets in July 2014.
Based on net result attributable to shareholders of the Parent Company.
An extensive list of definitions can be found on www.lundin-petroleum.com under the heading "Definitions".
TUSD Thousand USD MSEK Million SEK MUSD Million USD
| EBITDA | Earnings Before Interest, Tax, | boe | Barrels of oil equivalents |
|---|---|---|---|
| Depreciation and Amortisation | boepd | Barrels of oil equivalents per day | |
| CAD | Canadian dollar | bopd | Barrels of oil per day |
| CHF | Swiss franc | Mbbl | Thousand barrels |
| EUR | Euro | Mboe | Thousand barrels of oil equivalents |
| NOK | Norwegian krona | Mboepd | Thousand barrels of oil equivalents per day |
| RUR | Russian rouble | Mbopd | Thousand barrels of oil per day |
| SEK | Swedish krona | Mcf | Thousand cubic feet |
| USD | US dollar | ||
| TSEK | Thousand SEK | ||
I am pleased to report that, despite the challenging market conditions in the oil and gas industry particularly relating to low oil prices, Lundin Petroleum is on track to meet our 2015 objectives of first oil from Edvard Grieg and the go ahead of the Johan Sverdrup project. Our Company is in strong health with a production base which will grow significantly, cost of operations which going forward will be below USD 10 per barrel and with strong access to liquidity to withstand the current low oil price environment.
We have already brought onstream this year the Bertam field, offshore Malaysia and the Bøyla field, offshore Norway. I am pleased with the performance from both fields where we expect production to increase throughout the year as more development wells are drilled in Bertam and the impact of water injection and the second production well is seen at Bøyla. However production from the Brynhild field, offshore Norway, which came onstream in December 2014, has been very disappointing. The production efficiency of the Haewene Brim FPSO has been below forecast due to a number of issues particularly relating to topside efficiency and water handling constraints. Brynhild produced just over 3,000 barrels of oil per day during the first half of the year which was over 60 percent below forecast. We have seen improvements in production over recent weeks but we have revised our production efficiency forecasts to what we believe are more realistic levels going forward, which coupled with the first half production will have a negative impact on our 2015 production guidance.
We have made good progress with the Edvard Grieg development project and we remain on track for first production by the end of 2015. Following the successful completion of the Edvard Grieg topsides we had to wait a couple of months for the arrival of the "Thialf" heavy lift crane. The topside installation has now been successfully completed and the offshore hook-up and commissioning is underway. The Safe Boreas flotel is bridge-linked to the platform and over 400 people are currently on board and involved with offshore operations. The delay in arrival of the heavy lift crane has pushed our expected first oil date from early fourth quarter to end fourth quarter with a consequent impact on our 2015 production guidance.
We are still targeting a 2015 exit production rate of 75,000 barrels of oil per day after first oil from Edvard Grieg. We have however revised our 2015 production guidance to 32,000 barrels of oil equivalents per day predominantly as a result of the Brynhild revised production forecast and the delay of the installation of Edvard Grieg topsides. This revised forecast assumes only a limited contribution from Edvard Grieg due to the assumption of first oil in late December 2015.
We have made good progress on Johan Sverdrup with a number of key milestones achieved.
The Johan Sverdrup Phase 1 plan of development (PDO) was completed and submitted to the Norwegian Ministry of Petroleum and Energy for approval in February 2015. The PDO was endorsed by the Norwegian Parliament in June 2015 and I expect we will receive final approval from the Norwegian Ministry of Petroleum and Energy later this month.
As a result of the lack of unanimous agreement between partners regarding the unitisation of the Johan Sverdrup field, the Minister of Petroleum and Energy determined the partners' final working interests. It was announced in July 2015 that Lundin Petroleum's working interest in Johan Sverdrup increased to 22.60 percent from 22.12 percent. As I said in my previous Letter to Shareholders, we would accept the final decision of the Minister in respect of the Unit Operating Agreement. Nevertheless, I think it is important to state that yet again the Norwegian Petroleum and Energy Ministry has acted in an exemplary fashion throughout this process. From a technical perspective they have taken into account all the technical data in reaching their decision and have supported an agreement which will ultimately maximise the Johan Sverdrup resources for the benefit of all stakeholders.
We have seen excellent progress in the award of major contracts for Phase 1 Johan Sverdrup development. Contracts for all the topsides, drilling, engineering and heavy lift operations have now been awarded at cost levels which provide an early level of confidence that the Phase 1 development costs may be able to be ultimately reduced. We are also pleased that the project schedule remains on track for first oil in late 2019.
Exploration remains a key focus for Lundin Petroleum. We have been one of the most successful explorers over recent years with a key focus on Norway and South East Asia. Our ability to find resources at such a low "finding cost" has been the major catalyst to the creation of shareholder value. We believe with a focused approach that this will continue. Our appraisal programme in the southern Barents Sea at Alta is ongoing and despite the low oil prices we will drill further exploration wells in the area over the next few years. We strongly believe this region will deliver sufficient resources and this will lead to commercial development activity.
I am also excited about the near field opportunities in areas such as Edvard Grieg. I believe that the southeastern part of Edvard Grieg contains material resource upside and that discoveries such as Luno II, together with the prospective resource potential from the Luno II North prospect could be commercially viable tie-back fields to Edvard Grieg. As experienced with the Alvheim field development, the infrastructure of Edvard Grieg will in my view produce more hydrocarbons than is contained in the base Edvard Grieg plan of development. As the largest acreage holder in this region Lundin Petroleum will be the major beneficiary.
At a macro level, the oil markets are difficult to call right now. Despite the reduction of over 50 percent in the number of drilling rigs operational in the U.S., onshore oil business production levels have remained firm in this market. This is due partly to continued operational efficiency improvements and lower costs achieved by operators as well as the inventory of non-completed wells. I personally do not believe this is sustainable but I have been surprised as to how well production levels have held up. At the same time OPEC production has increased and the market is now trying to assess the impact of potential further production increases in Iran and Iraq. I still believe that at current oil prices there will be limited investment in new production capacity. As a result, capital investment levels will be low and ultimately will impact supply levels which will reduce over time. This will be the catalyst for oil prices to increase. In the short term we have to be prepared for continued volatility and the potential for a sustained period of lower oil prices and be ready to take advantage of any opportunities this may present.
I announced recently that after 13 years as President and CEO of Lundin Petroleum I would be stepping down from executive duties with the Company so this will be my last Letter to Shareholders. I am extremely proud as to what we have achieved in building Lundin Petroleum over this period into the largest independent exploration and production company in Europe and in the process creating excellent returns for our shareholders. I will remain on the Board and as a shareholder. The Company is in excellent health, has a great management team, a clear strategy and strong liquidity. I have worked for the last 20 years with Alex Schneiter, the new President and CEO, and I fully support his appointment. He will do a great job and I am convinced under his leadership the Company will continue to outperform. It has been an absolute pleasure to work with so many talented people at Lundin Petroleum, a Board of Directors always there to support the management team and provide guidance and a major shareholder in the Lundin family who created the culture to allow the Company to be so successful. I have enjoyed every minute of it and would like to thank you, all our shareholders, for your trust and support.
Yours Sincerely,
C. Ashley Heppenstall President and CEO
Stockholm, 5 August 2015
Lundin Petroleum has exploration and production assets focused upon three core areas: Norway, South East Asia and Continental Europe. Norway continues to represent the majority of Lundin Petroleum's operational activities with production for the six month period ended 30 June 2015 (reporting period) accounting for 69 percent of total production and with 79 percent of Lundin Petroleum's total reserves as at the end of 2014.
Lundin Petroleum has 187.5 million barrels of oil equivalent (MMboe) of reserves as at 31 December 2014 as certified by an independent third party. Lundin Petroleum also has a number of discovered oil and gas resources which classify as contingent resources and are not yet classified as reserves. Excluding the major Johan Sverdrup field located in Norway, the best estimate contingent resources net to Lundin Petroleum amount to 404 MMboe as at 31 December 2014. The Johan Sverdrup field contains gross contingent resources of between 1.7 and 3.0 billion boe and Lundin Petroleum will book its net working interest in Johan Sverdrup as reserves once the unitisation agreement has been finalised.
Production for the reporting period amounted to 27.4 thousand barrels of oil equivalents per day (Mboepd) (compared to 26.0 Mboepd over the same period in 2014) and was comprised as follows:
| Production in Mboepd |
1 Jan 2015– 30 Jun 2015 6 months |
1 Apr 2015– 30 Jun 2015 3 months |
1 Jan 2014– 30 Jun 2014 6 months |
1 Apr 2014– 30 Jun 2014 3 months |
1 Jan 2014– 31 Dec 2014 12 months |
|---|---|---|---|---|---|
| Crude oil | |||||
| Norway | 16.7 | 16.2 | 16.6 | 16.2 | 15.0 |
| France | 2.9 | 2.9 | 2.9 | 2.9 | 2.9 |
| Malaysia | 2.2 | 4.3 | – | – | – |
| Total crude oil production | 21.8 | 23.4 | 19.5 | 19.1 | 17.9 |
| Gas | |||||
| Norway | 2.2 | 2.2 | 3.0 | 2.9 | 2.6 |
| Netherlands | 1.7 | 1.6 | 2.0 | 1.9 | 1.9 |
| Indonesia | 1.7 | 1.7 | 1.5 | 1.5 | 1.4 |
| Total gas production | 5.6 | 5.5 | 6.5 | 6.3 | 5.9 |
| Total production | |||||
| Quantity in Mboe | 4,951.5 | 2,629.1 | 4,702.7 | 2,312.4 | 8,688.8 |
| Quantity in Mboepd | 27.4 | 28.9 | 26.0 | 25.4 | 23.8 |
Note: The comparatives have been restated following the sale of the Russian onshore assets in 2014.
| Production in Mboepd |
WI 1 | 1 Jan 2015- 30 Jun 2015 6 months |
1 Apr 2015- 30 Jun 2015 3 months |
1 Jan 2014- 30 Jun 2014 6 months |
1 Apr 2014- 30 Jun 2014 3 months |
1 Jan 2014- 31 Dec 2014 12 months |
|---|---|---|---|---|---|---|
| Alvheim | 15% | 8.1 | 7.6 | 10.0 | 10.3 | 9.6 |
| Volund | 35% | 5.4 | 5.0 | 8.9 | 8.1 | 7.4 |
| Bøyla | 15% | 1.9 | 1.9 | – | – | – |
| Brynhild | 90% | 3.2 | 3.3 | – | – | 0.1 |
| Gaupe | 40% | 0.3 | 0.6 | 0.7 | 0.7 | 0.5 |
| 18.9 | 18.4 | 19.6 | 19.1 | 17.6 |
1 Lundin Petroleum's working interest (WI) Production from the Alvheim field during the reporting period has been below forecast due to maintenance work on one of the gas compressors on the Alvheim FPSO as well as two wells being shut-in as a result of near-by infill drilling operations and well integrity issues respectively. The reservoir on the Alvheim field continues to perform well and the Alvheim FPSO also continues to achieve excellent uptime, with in excess of 95 percent production uptime during the reporting period. The drilling of a new infill well on Alvheim has been completed by the Transocean Winner rig and the well commenced production in April 2015. Thereafter the Transocean Winner rig worked-over the Alvheim KB3 well which re-commenced production in May 2015. The Transocean Winner rig has subsequently commenced the drilling of a further multi-lateral infill well which is expected to commence production in late 2015. A further infill well is planned to be drilled with production expected to commence in mid-2016. The development of the Viper/Kobra discoveries was sanctioned by the Alvheim partnership in December 2014 with two production wells planned to be drilled in 2016 with an expected production start-up in late 2016. The cost of operations for the Alvheim field, excluding well intervention work, was below USD 6 per barrel during the reporting period.
The Volund field production during the reporting period has been better than forecast due to good reservoir performance. Further infill opportunities have been identified on the Volund field and at least one further infill well is planned to be drilled. The cost of operations for the Volund field during the reporting period was below USD 5 per barrel.
The Bøyla field commenced production on 19 January 2015 from one production well. The field has produced as expected during the reporting period with the water injection well coming on-line in March 2015. The third and final development well was drilled and completed during the reporting period and the well will be tied-in and commence production during the third quarter of 2015 when the field is expected to reach plateau production.
The production from the Brynhild field during the reporting period has been below forecast. The initial production, which commenced in December 2014, was achieved from two production wells whilst the third and final production well and one water injection well have been successfully drilled and tied-in during the reporting period and are awaiting final commissioning. The Haewene Brim FPSO production efficiency has been below forecast due to a number of issues, particularly related to topside efficiency and water handling constraints. There has been some improvement seen over recent weeks but going forward the facilities uptime efficiency will remain challenging. Production during the reporting period has also been impacted by a planned shut-in of the field during heavy lift operations in relation to subsea installations activities on the field as well as a rig move.
Despite no remaining reserves being attributed to the Gaupe field, the field recommenced production in April 2015 and will be produced intermittently subject to favourable economic conditions.
| Licence | Field | WI | Operator | PDO Approval | Estimated gross reserves |
Production start expected |
Gross plateau production rate expected |
|---|---|---|---|---|---|---|---|
| PL338 | Edvard Grieg | 50% | Lundin Petroleum |
June 2012 | 187 MMboe | Q4 2015 | 100.0 Mboepd |
| Various | Ivar Aasen | 1.385% | Det norske | May 2013 | 192 MMboe | Q4 2016 | 65.0 Mboepd |
| Various | Johan Sverdrup | 22.60% | Statoil | Expected August 2015 |
1.7–3.0 billion boe | Late 2019 | 550.0–650.0 Mboepd |
The Edvard Grieg field development is progressing as expected and has achieved a number of milestones during the reporting period. In April 2015, Kværner completed the construction of the topsides on time and on budget. The onshore commissioning of the topsides was also completed and offshore installation of the topsides on the pre-installed jacket was successfully completed during July 2015 by the Heerema heavy lift vessel Thialf. The newbuild flotel Safe Boreas which is being used for the offshore commissioning phase was bridge-linked to the Edvard Grieg platform in July 2015 and the offshore hook-up and commissioning operations have begun. The 94 km gas pipeline was installed in 2014 and the 43 km oil pipeline to the Grane oil export system was successfully installed during the reporting period. Development drilling commenced during the third quarter of 2014 with the Rowan Viking jack-up rig and drilling is progressing with the first two production wells successfully completed and ready for first oil once they have been hooked-up to the platform. First oil from the pre-drilled wells is expected in the fourth quarter of 2015 following the completion of the offshore hook-up and commissioning. Plateau production from the Edvard Grieg field is expected during mid-2016 and development drilling will continue into 2017.
Following last year's successful appraisal well on the southeastern part of Edvard Grieg, a second appraisal well was spudded in June 2015 in the southern part of Edvard Grieg field to better understand the distribution of this sandstone with the potential to increase gross reserves by up to 50 MMboe.
Ivar Aasen is being developed with a steel jacket platform with the topside facilities consisting of a living quarter and drilling facilities with oil, gas and water separation and onward export to the Edvard Grieg platform for final processing and pipeline export. The steel jacket was successfully installed in June 2015 and the pipeline installation is scheduled to commence during the third quarter of 2015. The topside construction is approximately 70 percent complete with mechanical completion expected by year end 2015. The topsides installation is scheduled during the summer of 2016. Ivar Aasen is forecast to come onstream during the fourth quarter of 2016.
The Johan Sverdrup project is progressing on schedule with a significant number of contracts now awarded.
In February 2015, the Johan Sverdrup partnership submitted a Plan for Development and Operations (PDO) for Phase 1 to the Ministry of Petroleum and Energy (MPE) and the Norwegian Parliament endorsed the PDO in June 2015. The PDO for Phase 1 also outlines certain concepts for the full field development involving an expected full field gross plateau production level of between 550,000 boepd and 650,000 boepd and gross contingent resources of between 1.7 to 3.0 billion boe with approximately 95 percent of the resources being oil.
In parallel with the PDO submission, the majority of the Johan Sverdrup partnership also submitted a unit operating agreement for the Johan Sverdrup field with a working interest of 22.12 percent to Lundin Petroleum. Due to the lack of agreement on the unitisation of the field it was left to the Minister of Petroleum and Energy to determine the partners' final working interest within the unitisation agreement. On 2 July 2015 the Minister of Petroleum and Energy announced the final working interest apportionment for the Johan Sverdrup field which resulted in Lundin Petroleum's working interest being increased to 22.60 percent from 22.12 percent.
The PDO for Phase 1 involves a field centre, consisting of one processing platform, one riser platform, one wellhead platform with drilling facilities and one living quarter platform. The platforms will be installed on steel jackets in 120 metres of water and will be bridge-linked. A significant number of contracts have already been awarded for the development of Phase 1. Notably all four topside contracts have been awarded, with EPC type contracts being awarded to Aibel (drilling platform) and Kværner/KBR (living quarters and utilities) whilst a fabrication contract has been awarded to Samsung Heavy Industries (riser platform and processing platform) with Aker Solutions being contracted for the procurement and engineering of the riser and processing platforms. The contract for the heavy lift installations for three of the topsides have been awarded to Allseas and the contract for the construction of the steel jacket for the riser platform have been awarded to Kværner which started to cut steel for the jacket during the reporting period. Odfjell drilling has been awarded contracts for drilling of the wells with the drilling operations scheduled to commence in 2016.
The Phase 1 development is scheduled to start production in late 2019 and is forecast to have a gross production capacity of between 315,000 and 380,000 bopd. It is anticipated that 35 production and injection wells will be drilled to support Phase 1 production of which 14 wells will be drilled prior to first oil with a semi-submersible rig to facilitate Phase 1 plateau production.
The Phase 1 capital expenditure has been estimated at gross NOK 117 billion with the full field capital expenditure, including Phase 1, estimated at between NOK 170 to 220 billion.
| Licence | Operator | WI | Well | Spud Date | Status |
|---|---|---|---|---|---|
| PL609 | Lundin Petroleum | 40% | 7220/11-2 & 7220/11-2A |
March 2015 | Completed June 2015 |
| PL609 | Lundin Petroleum | 40% | 7220/11-3 | June 2015 | Ongoing |
| PL338 | Lundin Petroleum | 50% | 16/1-23S | June 2015 | Ongoing |
During the reporting period Lundin Petroleum completed the Alta appraisal well 7220/11-2 and sidetrack well 7220/11-2 A in the southern Barents Sea. The wells were drilled on the western part of the Alta discovery, approximately 6.5 km southwest of the discovery well 7220/11-1. The well 7220/11-2 encountered a 50 metres thick gas column in varying reservoir quality. The sidetrack well 7220/11-2 A was drilled a further 330 metres to the west and encountered moveable oil in improving reservoir quality and tested a maximum flow rate of 860 bopd and 0.65 million cubic feet of gas per day. Both the vertical well and the sidetrack proved pressure communication with the discovery well 6.5 km to the northeast. The second Alta appraisal well 7220/11-3 in 2015 is currently ongoing on the eastern side of the Alta structure approximately 4.3 km south of the discovery well to test reservoir quality and structural closure.
| Licence | Well | Spud Date | Target | WI | Operator | Result |
|---|---|---|---|---|---|---|
| Utsira High | ||||||
| PL338C | 16/1-24 | February | Gemini | 50% | Lundin Petroleum | Dry |
| PL674BS | 26/10-1 | January | Zulu | 35% | Lundin Petroleum | Gas discovery – non-commercial |
| PL359 | 16/4-9S | June | Luno II North | 50% | Lundin Petroleum | Ongoing |
| Southern Barents Sea | ||||||
| PL708 | Fourth quarter | Ørnen | 40% | Lundin Petroleum | ||
| PL609 | Third quarter | Neiden | 40% | Lundin Petroleum | ||
| Other Areas | ||||||
| PL579 | 33/2-1 | March | Morkel | 50% | Lundin Petroleum | Oil discovery – non-commerical |
| PL734 | 10/4-1 | June | Zeppelin | 30% | Wintershall | Dry |
| PL700 | Fourth quarter | Lorry | 40% | Lundin Petroleum | ||
Lundin Petroleum has completed four exploration wells in Norway during the reporting period.
The drilling of the Zulu prospect in PL674BS encountered a 24 metres sand sequence containing gas. The Zulu gas discovery is viewed as being non-commercial.
The drilling of the Gemini prospect in PL338C located immediately to the west of the Edvard Grieg field failed to encounter any hydrocarbons and the well was plugged and abandoned as dry.
The Zeppelin prospect in PL734 in the southern North Sea was announced as dry in July 2015. The well, which was operated by Wintershall, encountered a Vestland Group reservoir but was dry.
The Morkel prospect in PL579 in the northern North Sea was announced as a non-commercial oil discovery in June 2015. The well was drilled around 40 km northwest of the Snorre field and encountered Triassic sandstone over a 173 metre reservoir interval with low reservoir quality and poor production characteristics.
Lundin Petroleum will drill another four wells offshore Norway during 2015 targeting net unrisked prospective resources of approximately 295 MMboe.
Lundin Petroleum, together with 32 other companies signed a contract last year with Western Geco and PGS for an extended 3D seismic acquisition in the Norwegian east Barents Sea ahead of the 23rd licensing round. The 3D acquisition was completed in the third quarter of 2014 and the processing is scheduled to be completed in the summer of 2015. In January 2015, the Norwegian Ministry of Petroleum and Energy announced that 57 blocks, or part blocks, will be offered for licensing in the 23rd Licensing round with the majority of blocks being located in the Barents Sea. The deadline for submitting licence applications is in December 2015 with awards expected to be announced during the first half of 2016. The Ministry of Petroleum and Energy has also announced the APA 2015 licensing round with an application deadline in September 2015 with possible awards expected during the first quarter of 2016.
In January 2015, the Ministry of Petroleum and Energy announced the licence awards in the 2014 APA licensing round. Lundin Petroleum was awarded eight licences of which six were awarded to Lundin Petroleum as operator.
During the reporting period, Lundin Petroleum farmed out 30 percent in PL338C (WI 50% after farm-out) and 30 percent in PL544 (WI 50% after farm-out) to Lime Petroleum Norway. Lundin Petroleum's working interest in PL410 located on the Utsira High has increased to 82.352 percent following partner withdrawals. During the reporting period licences PL490, PL641, PL646, PL639 and PL546 have been relinquished and Lundin Petroleum has withdrawn from PL583 and assumed operatorship of PL533 which is situated immediately to the west of the Alta discovery in the southern Barents Sea. Certain of the above transactions and relinquishments remain subject to governmental approvals.
In July 2015, Lundin Petroleum signed an agreement with EnQuest Norge AS whereby Lundin Petroleum has been assigned a 35 percent operated working interest in PL758 and PL800. The agreement is subject to government approval.
| Production in Mboepd |
WI | 1 Jan 2015– 30 Jun 2015 6 months |
1 Apr 2015– 30 Jun 2015 3 months |
1 Jan 2014– 30 Jun 2014 6 months |
1 Apr 2014– 30 Jun 2014 3 months |
1 Jan 2014– 31 Dec 2014 12 months |
|---|---|---|---|---|---|---|
| France | ||||||
| – Paris Basin | 100%1 | 2.3 | 2.3 | 2.4 | 2.4 | 2.5 |
| – Aquitaine | 50% | 0.6 | 0.6 | 0.5 | 0.5 | 0.4 |
| Netherlands | Various | 1.7 | 1.6 | 2.0 | 1.9 | 1.9 |
| 4.6 | 4.5 | 4.9 | 4.8 | 4.8 |
1 Working interest in the Dommartin Lettree field 42.5 percent.
Production levels during the reporting period from France are substantially in line with forecast with good production performance from Aquitaine following the completion of certain well work-over activity. The construction of onshore facilities and the drilling and completion of two development wells on the Vert la Gravelle re-development project in the Paris Basin has been finalised and the wells have commenced production.
Production from the Netherlands has been in line with the forecast during the reporting period.
The K5-A5 development well within the K4/K5 unit (WI 1.216%) was successfully drilled in 2014 and commenced production in May 2015. The K5-A6 development well within the K4/K5 unit (WI 1.216%) was drilled during the reporting period, however the reservoir was found to be depleted and the well has been plugged and abandoned. The E17-A5 (WI 1.20%) development well has been successfully drilled and completed during the reporting period and commenced production in July 2015. The Slootdorp-6 and 7 onshore development wells (WI 7.2325%) have both been completed and put into production in July 2015.
The Langezwaag-2 exploration well on the Gorredijk licence (WI 7.75%) was successfully drilled in 2014 and was put into production in January 2015.
Malaysia
Production
| Production in Mboepd |
WI | 1 Jan 2015– 30 Jun 2015 6 months |
1 Apr 2015– 30 Jun 2015 3 months |
1 Jan 2014– 30 Jun 2014 6 months |
1 Apr 2014– 30 Jun 2014 3 months |
1 Jan 2014– 31 Dec 2014 12 months |
|---|---|---|---|---|---|---|
| Bertam | 75% | 2.2 | 4.3 | – | – | – |
The Bertam field on PM307 (WI 75%) achieved first oil in April 2015, commencing production from four pre-drilled wells. Since production start-up another three wells have been completed and put onstream and a further two wells are expected to commence production during August 2015. The drilling of the development wells is continuing until late 2015 when the Bertam field will achieve its plateau production rate of gross 15,000 boepd. The Bertam field is estimated to contain gross reserves of 18 MMboe and the total gross development costs are estimated at MUSD 400, excluding any FPSO related costs.
One exploration well is planned to be drilled on Block PM307 during the fourth quarter of 2015 following the completion of the Bertam development drilling campaign. The exploration well is targeting the Mengkuang-1 oil prospect, estimated to contain gross unrisked prospective resources of 21 MMboe.
Lundin Petroleum is currently high-grading its prospect inventory for SB307/SB308 (WI 42.5%) on existing 3D seismic, with a view to identify drilling targets for potential drilling in 2016. In July 2015, Lundin Petroleum assumed EnQuest's 42.5 percent working interest in SB307/SB308 increasing its working interest to 85 percent in SB307/SB308 subject to government approval and pre-emption rights.
| Production in Mboepd |
WI | 1 Jan 2015– 30 Jun 2015 6 months |
1 Apr 2015– 30 Jun 2015 3 months |
1 Jan 2014– 30 Jun 2014 6 months |
1 Apr 2014– 30 Jun 2014 3 months |
1 Jan 2014– 31 Dec 2014 12 months |
|---|---|---|---|---|---|---|
| Singa | 25.9% | 1.7 | 1.7 | 1.5 | 1.5 | 1.4 |
The production from the Singa field has been in line with the forecast during the reporting period. The field was shut-in during part of 2014 to allow for a re-routing of the gas pipeline and re-commenced production in late 2014.
Lundin Petroleum is undertaking geological and technical studies on the Cendrawasih VII Block (WI 100%), offshore eastern Indonesia. As part of the 2D seismic acquisition over Cendrawasih VIII approximately 200 km of 2D lines were also shot over the Parson prospect on Cendrawasih VII. Processing of these lines was completed during the reporting period and interpretation is ongoing.
In November 2014 Lundin Petroleum entered into a Joint Study Agreement for 100 percent of the Cendrawasih VIII Block which is contiguous to Cendrawasih VII Block. The acquisition and processing of approximately 2,300 km of 2D seismic was successfully completed during the reporting period and interpretation is ongoing.
In the Lagansky Block (WI 70%) in the northern Caspian a significant oil discovery, Morskaya, was made in 2008 and is estimated to contain gross best estimate contingent resources of 157 MMboe. In May 2015, Lundin Petroleum announced that Rosnedra, the Russian licensing authorities, had issued a production licence for the Morskaya field located within the Lagansky Block.
During the reporting period, Lundin Petroleum submitted its 2014 Communication on Progress to the UN Global Compact on its implementation of the Ten Principles and its Carbon Disclosure Project report on its climate change strategy and emissions performance.
During the reporting period, Lundin Petroleum recorded four Lost Time Incidents (LTI); its year to date LTI rate stands at 0.44 per 200,000 hours, while its total recordable incident rate (TRIR) is 0.80.
The net result for the six month period ended 30 June 2015 (reporting period) amounted to MUSD -171.0 (MUSD 0.8). The decrease was mainly due to lower oil prices and a higher financial expense as a result of the strong US dollar during the reporting period generating a foreign exchange charge, partially offset by a five percent increase in production. The net result attributable to shareholders of the Parent Company for the reporting period amounted to MUSD -168.8 (MUSD 3.2) representing earnings per share of USD -0.55 (USD 0.01).
Earnings before interest, tax, depletion and amortisation (EBITDA) for the reporting period amounted to MUSD 192.4 (MUSD 349.3) representing EBITDA per share of USD 0.62 (USD 1.13). Operating cash flow for the reporting period amounted to MUSD 347.3 (MUSD 497.0) representing operating cash flow per share of USD 1.12 (USD 1.60).
There have been no significant changes in the Group during the reporting period.
Revenue for the reporting period amounted to MUSD 279.1 (MUSD 460.8) 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 260.6 (MUSD 483.3). The average price achieved by Lundin Petroleum for a barrel of oil equivalent amounted to USD 56.76 (USD 98.45) and is detailed in the following table. The average Dated Brent price for the reporting period amounted to USD 57.84 (USD 108.93) per barrel.
| Net sales of oil and gas for the reporting period are detailed in Note 3 and were comprised as follows: | |||||||
|---|---|---|---|---|---|---|---|
| Sales Average price per boe expressed in USD |
1 Jan 2015– 30 Jun 2015 6 months |
1 Apr 2015– 30 Jun 2015 3 months |
1 Jan 2014– 30 Jun 2014 6 months |
1 Apr 2014– 30 Jun 2014 3 months |
1 Jan 2014– 31 Dec 2014 12 months |
|---|---|---|---|---|---|
| Crude oil sales | |||||
| Norway | |||||
| – Quantity in Mboe | 2,838.2 | 1,133.4 | 3,210.9 | 1,635.0 | 5,183.3 |
| – Average price per boe | 58.82 | 66.64 | 113.50 | 116.51 | 102.35 |
| France | |||||
| – Quantity in Mboe | 551.2 | 347.9 | 453.0 | 220.4 | 1,028.7 |
| – Average price per boe | 60.33 | 61.77 | 107.79 | 110.08 | 94.08 |
| Netherlands | |||||
| – Quantity in Mboe | 0.6 | 0.1 | 0.6 | – | 1.1 |
| – Average price per boe | 50.95 | – | 93.90 | – | 91.64 |
| Malaysia | |||||
| – Quantity in Mboe | 222.7 | 222.7 | – | – | – |
| – Average price per boe | 64.86 | 64.86 | – | – | – |
| Total crude oil sales | |||||
| – Quantity in Mboe | 3,612.7 | 1,704.1 | 3,664.5 | 1,855.4 | 6,213.1 |
| – Average price per boe | 59.42 | 65.41 | 112.79 | 115.75 | 100.98 |
| Gas and NGL sales | |||||
| Norway | |||||
| – Quantity in Mboe | 391.8 | 196.0 | 638.3 | 338.6 | 1,080.8 |
| – Average price per boe | 48.16 | 46.73 | 59.49 | 52.80 | 56.02 |
| Netherlands | |||||
| – Quantity in Mboe | 303.8 | 142.9 | 362.6 | 174.5 | 687.9 |
| – Average price per boe | 41.70 | 41.42 | 55.67 | 49.44 | 51.11 |
| Indonesia | |||||
| – Quantity in Mboe | 282.6 | 145.8 | 243.6 | 122.7 | 457.2 |
| – Average price per boe | 50.90 | 50.93 | 48.33 | 48.56 | 47.87 |
| Total gas and NGL sales | |||||
| – Quantity in Mboe | 978.2 | 484.7 | 1,244.5 | 635.8 | 2,225.9 |
| – Average price per boe | 46.94 | 46.43 | 56.19 | 51.06 | 52.83 |
| Total sales | |||||
| – Quantity in Mboe | 4,590.9 | 2,188.8 | 4,909.0 | 2,491.2 | 8,439.0 |
| – Average price per boe | 56.76 | 61.21 | 98.45 | 99.23 | 88.28 |
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. Permanent differences arise as a result of paying royalties in kind as well as the effects from production sharing agreements. 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 a net credit of MUSD 9.7 (charge of MUSD 30.5) in the reporting period. There was an underlift of entitlement movement on the Brynhild and Alvheim fields during the reporting period due to the timing of the cargo liftings compared to production.
Other revenue amounted to MUSD 8.8 (MUSD 8.0) for the reporting period and included third party Bertam FPSO lease income, a quality differential compensation on Alvheim blended crude, tariff income from France and the Netherlands and income for maintaining strategic inventory levels in France.
Production costs including inventory movements for the reporting period amounted to MUSD 64.5 (MUSD 80.3) and are detailed in the table below.
| Production costs | 1 Jan 2015– 30 Jun 2015 6 months |
1 Apr 2015– 30 Jun 2015 3 months |
1 Jan 2014– 30 Jun 2014 6 months |
1 Apr 2014– 30 Jun 2014 3 months |
1 Jan 2014– 31 Dec 2014 12 months |
|---|---|---|---|---|---|
| Cost of operations | |||||
| – In MUSD | 55.8 | 34.4 | 52.5 | 21.9 | 94.4 |
| – In USD per boe | 11.27 | 13.10 | 11.16 | 9.46 | 10.86 |
| Tariff and transportation expenses | |||||
| – In MUSD | 5.8 | 3.3 | 9.8 | 5.0 | 18.4 |
| – In USD per boe | 1.18 | 1.25 | 2.08 | 2.14 | 2.12 |
| Royalty and direct production taxes | |||||
| – In MUSD | 1.5 | 0.8 | 1.9 | 1.0 | 3.6 |
| – In USD per boe | 0.31 | 0.31 | 0.40 | 0.40 | 0.41 |
| Change in inventory position | |||||
| – In MUSD | -5.5 | -3.1 | -1.6 | -1.4 | -0.8 |
| – In USD per boe | -1.11 | -1.17 | -0.35 | -0.62 | -0.09 |
| Other | |||||
| – In MUSD | 6.9 | 3.9 | 17.7 | 15.4 | -49.1 |
| – In USD per boe | 1.39 | 1.47 | 3.78 | 6.74 | -5.65 |
| Total production costs | |||||
| – In MUSD | 64.5 | 39.3 | 80.3 | 41.9 | 66.5 |
| – In USD per boe | 13.04 | 14.96 | 17.07 | 18.12 | 7.65 |
Note: USD per boe is calculated by dividing the cost by total production volume for the period.
The total cost of operations for the reporting period was MUSD 55.8 (MUSD 52.5). The reporting period included costs of MUSD 7.3 associated with well intervention work on the Alvheim field. The total cost of operations excluding operational projects amounted to MUSD 46.8 (MUSD 36.2).The increase versus the comparative period is attributable to operating costs of the Brynhild and Bøyla fields which came onstream in the fourth quarter of 2014 and the first quarter of 2015 respectively, partly offset by the impact of the stronger US Dollar on the funding of non-US Dollar denominated expenditures in the reporting period
The cost of operations per barrel including operational projects amounted to USD 11.27 (USD 11.16) for the reporting period and excluding operational projects, the cost of operations amounted to USD 9.45 (USD 7.70) per barrel.
Tariff and transportation expenses for the reporting period amounted to MUSD 5.8 (MUSD 9.8). The decrease in costs compared to the same period last year is mainly due to lower volumes from the Volund and Gaupe fields in the reporting period.
Other costs amounted to MUSD 6.9 (MUSD 17.7) and related to the operating cost share arrangement on the Brynhild field whereby the amount of operating cost varies with the oil price until mid-2017. This arrangement is being marked-to-market against the oil price curve and due to the low oil price curve at the end of 2014, an asset was recognised as at 31 December 2014. This asset is being charged to the income statement over the remaining term of the arrangement.
Depletion costs amounted to MUSD 106.7 (MUSD 68.8) at an average rate of USD 21.54 (USD 14.61) per barrel and are detailed in Note 3. The higher depletion cost for the reporting period compared to the same period last year is due to the contributions of the Brynhild, Bøyla and Bertam fields, partly offset by no production volumes from the Gaupe field and lower production volumes on the Alvheim and Volund fields in the reporting period. Norway's contribution to the total depletion cost for the reporting period was 61 percent (67 percent) at an average rate of USD 19.09 (USD 13.08) per barrel. Included in the depletion cost for the reporting period is an amount of MUSD 8.2 (MUSD –) related to the Bertam FPSO.
Exploration costs expensed in the income statement for the reporting period amounted to MUSD 106.9 (MUSD 129.2) 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.
During the second quarter of 2015, exploration costs relating to Norway of MUSD 61.0 were expensed and mainly related to the unsuccessful well that was drilled in PL579 (Morkel).
During the first quarter of 2015, exploration costs relating to Norway of MUSD 44.9 were expensed and mainly related to two unsuccessful wells that were drilled in PL338C (Gemini) and PL674BS (Zulu).
The general, administrative and depreciation expenses for the reporting period amounted to MUSD 24.4 (MUSD 33.7) which included a charge of MUSD 5.0 (MUSD 7.8) in relation to the Group's long-term incentive plans (LTIP), see also Remuneration section below. Fixed asset depreciation charges for the reporting period amounted to MUSD 2.3 (MUSD 2.5).
Finance income for the reporting period amounted to MUSD 1.3 (MUSD 1.0) and is detailed in Note 4.
Finance costs for the reporting period amounted to MUSD 225.0 (MUSD 38.5) and are detailed in Note 5.
Interest expenses for the reporting period amounted to MUSD 27.8 (MUSD 6.8) and represented the portion of interest charged to the income statement. An additional amount of interest of MUSD 19.7 (MUSD 16.7) primarily associated with the funding of the Norwegian and Malaysian development projects was capitalised in the reporting period.
Net foreign exchange losses for the reporting period amounted to MUSD 176.7 (MUSD 8.8). This foreign exchange loss mainly relates to the revaluation of loan balances at the prevailing exchange rates at the end of the reporting period. The US Dollar strengthened against the Euro during the reporting period resulting in a net foreign exchange loss on the US Dollar denominated external loan which is borrowed by a subsidiary using Euro as functional currency. This foreign exchange loss was partly offset by a smaller foreign exchange gain relating to the strengthening of the Norwegian Krone against the Euro in the reporting period, generating a net foreign exchange gain on an intercompany loan balance denominated in Norwegian Krone. A strengthening US Dollar currency has a positive overall value effect on the business as it increases the purchasing power of the US Dollar to purchase the currencies in which the Group incurs operational expenditure. Lundin Petroleum has hedged certain foreign currency operational expenditure amounts against the US Dollar. For the reporting period, the net realised exchange loss on settled foreign exchange hedges amounted to MUSD 79.8 (MUSD 8.0 gain). There was a net foreign exchange gain of MUSD 27.3 (MUSD -35.7 loss) reported for the second quarter of 2015 resulting from the weakening of the US Dollar against the Euro partly offset by settled foreign currency hedges and a weakening of the Norwegian Krone against the Euro.
The amortisation of the deferred financing fees amounted to MUSD 6.1 (MUSD 6.1) for the reporting period and related to the expensing of the fees incurred in establishing the financing facilities, including the Norwegian exploration financing facility, over the period of usage of the facilities.
Loan facility commitment fees for the reporting period amounted to MUSD 5.2 (MUSD 11.4) with the decrease compared to the same period last year being due to the increased borrowings under the financing arrangements.
The tax credit for the reporting period amounted to MUSD 76.1 (charge of MUSD 97.6).
The current tax credit for the reporting period amounted to MUSD 132.8 (MUSD 116.5) which included MUSD 136.1 (MUSD 127.4) relating to the Norway exploration tax refund due to the significant level of development and exploration and appraisal expenditure in Norway in the reporting period and the tax depreciation on development expenditure incurred in prior years. The current tax credit in Norway for the reporting period is partly offset by the current tax charge relating to operations in France and the Netherlands.
The deferred tax charge for the reporting period amounted to MUSD 56.7 (MUSD 214.1) which predominantly related to Norway. The deferred tax charge 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 20 percent 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 net foreign exchange loss reported and by the uplift allowance applicable in Norway for development expenditures against the offshore 51 percent tax regime.
The net result attributable to non-controlling interest for the reporting period amounted to MUSD -2.2 (MUSD -2.4) and related mainly to the non-controlling interest's share in a Russian subsidiary which is fully consolidated.
Oil and gas properties amounted to MUSD 4,659.4 (MUSD 4,182.6) and are detailed in Note 7.
Development and exploration and appraisal expenditure incurred for the reporting period was as follows:
| Development expenditure in MUSD |
1 Jan 2015– 30 Jun 2015 6 months |
1 Apr 2015– 30 Jun 2015 3 months |
1 Jan 2014– 30 Jun 2014 6 months |
1 Apr 2014– 30 Jun 2014 3 months |
1 Jan 2014– 31 Dec 2014 12 months |
|---|---|---|---|---|---|
| Norway | 481.6 | 241.5 | 575.2 | 289.1 | 1,068.2 |
| France | 14.4 | 5.0 | 6.2 | 3.9 | 29.3 |
| Netherlands | 1.7 | 0.7 | 2.0 | 1.3 | 3.9 |
| Indonesia | -0.7 | -0.7 | – | – | -0.8 |
| Malaysia | 104.5 | 51.1 | 48.9 | 34.5 | 130.6 |
| 601.5 | 297.6 | 632.3 | 328.8 | 1,231.2 |
An amount of MUSD 481.6 (MUSD 575.2) of development expenditure was incurred in Norway during the reporting period, primarily on the Edvard Grieg, Brynhild, Ivar Aasen, and Johan Sverdrup field developments. In Malaysia, MUSD 104.5 (MUSD 48.9) was incurred during the reporting period on the Bertam field development.
An amount of MUSD 31.3 (MUSD 78.7) was incurred during the reporting period on the Bertam FPSO facilities. This amount is not shown in the table above and has been capitalised as part of other tangible fixed assets.
| Exploration and appraisal expenditure in MUSD |
1 Jan 2015– 30 Jun 2015 6 months |
1 Apr 2015– 30 Jun 2015 3 months |
1 Jan 2014– 30 Jun 2014 6 months |
1 Apr 2014– 30 Jun 2014 3 months |
1 Jan 2014– 31 Dec 2014 12 months |
|---|---|---|---|---|---|
| Norway | 169.0 | 88.6 | 211.0 | 97.8 | 572.8 |
| France | 0.4 | 0.3 | 1.7 | 1.4 | 5.9 |
| Indonesia | 2.7 | 2.3 | 27.6 | 1.7 | 47.5 |
| Malaysia | 4.6 | 3.7 | 11.4 | 9.6 | 42.7 |
| Russia | 3.6 | 3.0 | 1.9 | 1.0 | 4.0 |
| Other | 1.2 | 1.1 | 0.9 | 0.4 | 1.6 |
| 181.5 | 99.0 | 254.5 | 111.9 | 674.5 |
Exploration and appraisal expenditure of MUSD 169.0 (MUSD 211.0) was incurred in Norway during the reporting period, primarily on the appraisal drilling of the Alta discovery in the southern Barents Sea and the exploration wells on the Gemini, Zulu and Morkel prospects.
Other tangible fixed assets amounted to MUSD 220.5 (MUSD 200.3) and included amounts relating to the Bertam FPSO.
Financial assets amounted to MUSD 29.3 (MUSD 37.0) and are detailed in Note 8. Other shares and participations amounted to MUSD 7.6 (MUSD 4.7) and related to the shares held in ShaMaran Petroleum which are reported at market value with any change in value being recorded in other comprehensive income. The main change in the value since the year end relates to the additional shares acquired from the ShaMaran rights issue completed during the first quarter of 2015, see also Related Party Transactions section below. Brynhild operating cost share amounted to MUSD 20.0 (MUSD 31.0) and related to the long-term portion of the mark-to-market valuation of the arrangement where the share of the operating cost varies with the oil price.
Deferred tax assets amounted to MUSD 11.0 (MUSD 12.9) and are mainly related to the part of the tax loss carry forwards in the Netherlands that are expected to be utilised against future tax liabilities.
Other non-current assets amounted to MUSD 136.8 (MUSD –) and related to the Norwegian corporate tax refund in respect of the current year which will be received in December 2016.
Inventories amounted to MUSD 39.3 (MUSD 41.6) and included both well supplies mainly held in Norway and Malaysia and hydrocarbon inventories.
Trade and other receivables amounted to MUSD 173.2 (MUSD 163.5) and are detailed in Note 10. Trade receivables, which are all current, amounted to MUSD 53.0 (MUSD 40.3). Underlift amounted to MUSD 13.0 (MUSD 3.6) and was mainly attributable to a net underlift position in Norway on the Brynhild and Alvheim fields. Joint operations debtors amounted to MUSD 23.0 (MUSD 49.1) and the comparative amount included a significant amount that was settled in January 2015. Prepaid expenses and accrued income amounted to MUSD 44.8 (MUSD 41.5) and represented prepaid operational and insurance expenditure. Brynhild operating cost share amounted to MUSD 22.5 (MUSD 21.6) and related to the short-term portion of the mark-tomarket valuation of the arrangement where the share of the operating cost varies with the oil price. Other current assets amounted to MUSD 16.9 (MUSD 7.4) and included a receivable on Johan Sverdrup past costs following the assigned equity in the unit, VAT and other miscellaneous balances.
Current tax assets amounted to MUSD 348.5 (MUSD 373.6) and mainly related to the Norwegian corporate tax refund in respect of 2014 which is due to be received in December 2015. The amount is denominated in Norwegian Kroner and the movement in US Dollar terms since year end results from the strengthening of the US Dollar against the Norwegian Krone.
Cash and cash equivalents amounted to MUSD 93.0 (MUSD 80.5). Cash balances are held to meet ongoing operational funding requirements.
Financial liabilities amounted to MUSD 3,521.6 (MUSD 2,654.0) and are detailed in Note 11. Bank loans amounted to MUSD 3,553.0 (MUSD 2,690.0) and related to the outstanding loan under the Group's USD 4.0 billion revolving borrowing base facility. Capitalised financing fees relating to the establishment costs of the financing facilities, including the Norwegian exploration financing facility, amounted to MUSD 31.4 (MUSD 36.0) and are being amortised over the expected life of the financing facilities.
Provisions amounted to MUSD 335.4 (MUSD 288.0) and are detailed in Note 12. The provision for site restoration amounted to MUSD 324.1 (MUSD 274.1) and related to future decommissioning obligations. The provision has increased during the reporting period due to additions relating to the Norwegian and Malaysian development projects. Farm-in payment amounted to MUSD 5.3 (MUSD 7.5) and related to a provision for payments towards historic costs based on production milestones on Block PM307, Malaysia, see also Current Liabilities section.
Deferred tax liabilities amounted to MUSD 981.3 (MUSD 973.3) of which MUSD 852.4 (MUSD 844.8) related to Norway. 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 29.5 (MUSD 33.9) and related to the mark-to-market loss on outstanding interest rate hedges due to be settled after twelve months.
Other non-current liabilities amounted to MUSD 30.9 (MUSD 29.1) and mainly represent the full consolidation of a subsidiary in which the non-controlling interest entity has made funding advances in relation to LLC PetroResurs, Russia.
Trade and other payables amounted to MUSD 431.5 (MUSD 491.4) and are detailed in Note 13. Joint operations creditors and accrued expenses amounted to MUSD 315.8 (MUSD 383.5) and related mainly to the development and drilling activity in Norway and on the Bertam field, Malaysia. Other accrued expenses amounted to MUSD 41.1 (MUSD 46.1) and included an amount of MUSD 13.1 (MUSD 19.4) relating to the work remaining to be done on the Bertam FPSO. Short term bank loans amounted to MUSD 35.6 (MUSD –) and represented the amount that had been drawn under the Norwegian exploration financing facility. The liability for the long-term incentive plans amounted to MUSD – (MUSD 28.2) following the payment of the outstanding amounts under the 2009 phantom option plan.
Derivative instruments amounted to MUSD 76.7 (MUSD 101.4) and related to the mark-to-market loss on outstanding foreign currency and interest rate hedge contracts due to be settled within twelve months.
Current provisions amounted to MUSD 3.3 (MUSD 53.4). Included in the comparative period was MUSD 48.5 relating to a payment for historic costs on Block PM307, Malaysia, payable on first oil from the Bertam field. Following first oil from the Bertam field in April 2015, the liability was settled during the reporting period. The liability was in Malaysian Ringgit and due to the strengthening of the US Dollar against the Malaysian Ringgit and a reduction in the agreed historic costs, the amount paid was MUSD 34.8 in US Dollar terms. An amount of MUSD 3.3 (MUSD 4.9) relating to the current portion of the provision for Lundin Petroleum's Unit Bonus Plan is included in current provisions.
The business of the Parent Company is investment in and management of oil and gas assets. The net result for the Parent Company amounted to MSEK -40.6 (MSEK -77.9) for the reporting period.
The result included general and administrative expenses of MSEK 50.6 (MSEK 84.5) and finance income of MSEK 2.5 (MSEK 1.8).
Pledged assets of MSEK 7,578.2 (MSEK 8,717.8) relate to the accounting value of the pledge of the shares in respect of the financing facility entered into by its fully-owned subsidiary Lundin Petroleum BV, see also the Liquidity section below.
During the year, the Group has entered into transactions with related parties on a commercial basis as described below.
The Group received MUSD 0.2 (MUSD 0.2) from related parties for the provision of office and other services. The Group paid MUSD – (MUSD 0.1) to related parties in respect of services received.
Following a rights issue by ShaMaran Petroleum that was completed in February 2015, Lundin Petroleum acquired 46.5 million ShaMaran shares for a total consideration of CAD 4.65 million and received a further 7.3 million ShaMaran shares as a fee for guaranteeing the offering along with other major shareholders. As at 30 June 2015, Lundin Petroleum holds a total of 103.8 million ShaMaran shares, representing approximately 6.6 percent of the total outstanding ShaMaran shares at that date.
In 2014, Lundin Petroleum increased its financing facility to USD 4.0 billion. The financing facility is a revolving borrowing base facility secured against certain cash flows generated by the Group. The amount available under the facility is recalculated every six 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 and a charge over some of the bank accounts of the pledged companies. The pledged amount at 30 June 2015 is MUSD 920.2 (MUSD 1,126.8) equivalent and represents the accounting value of net assets of the Group companies whose shares are pledged as described in the Parent Company section above. The Group is not in breach of its financing facility agreement.
In April 2015, Lundin Petroleum entered into a NOK 4.5 billion Norwegian exploration financing facility with ten international banks. The facility is secured against the tax refunds generated from Lundin Norway's exploration and appraisal activities on the Norwegian Continental Shelf and extends until the end of 2016.
Lundin Petroleum has, through its subsidiary Lundin Malaysia BV, entered into Production Sharing Contracts (PSC) with Petroliam Nasional Berhad, the oil and gas company of the Government of Malaysia (Petronas). Bank guarantees have been issued in support of the work commitments and other related costs in relation to certain of these PSCs and the outstanding amount of the bank guarantees at 30 June 2015 was MUSD 40.3. An additional bank guarantee in support of work commitments in Indonesia was also in place at 30 June 2015 for an amount of MUSD 1.0.
In July 2015, Lundin Petroleum announced that the non-operated Zeppelin well on PL734 in the southern North Sea, Norway was a dry hole.
In July 2015, Lundin Petroleum signed an agreement with EnQuest Norge AS whereby Lundin Petroleum has been assigned a 35 percent operated working interest in PL758 and PL800. The agreement is subject to government approval.
In July 2015, Lundin Petroleum assumed EnQuest's 42.5 percent working interest in SB307/SB308 increasing its working interest to 85 percent subject to government approval and pre-emption rights.
Lundin Petroleum AB's issued share capital amounted to SEK 3,179,106 represented by 311,070,330 shares with a quota value of SEK 0.01 each. At 30 June 2015 the Company holds 2,000,000 of its own shares.
Lundin Petroleum's principles for remuneration and details of the long-term incentive plans are provided in the Company's 2014 Annual Report and in the materials provided to shareholders in respect of the 2015 AGM, available on www.lundin-petroleum.com.
The number of units relating to the awards made in 2013, 2014 and 2015 under the Unit Bonus Plan outstanding as at 30 June 2015 were 133,922, 260,016 and 441,831 respectively.
The AGM 2015 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 2015 and the 2015 award will be accounted for from the second half of the year. The total awards made in respect of 2015 was 705,406 and vest over three years subject to certain performance conditions being met by Lundin Petroleum.
The 2014 plan is effective from 1 July 2014 and the total number of awards made in respect of 2014 was 608,103 and the related cost is recognised on a straight line basis over the three year performance period. Each award was fair valued at the date of grant at SEK 81.40 using an option pricing model.
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).
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 2014.
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.
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 2014 Annual Report.
At 30 June 2015, Lundin Petroleum had outstanding currency swap hedges to meet a part of the future NOK operational requirements as summarised below:
| Buy | Sell | Average contractual exchange rate |
Settlement period |
|---|---|---|---|
| MNOK 1,512.7 | MUSD 235.1 | NOK 6.43:USD 1 | Jul 2015 – Dec 2015 |
| MNOK 1,251.8 | MUSD 182.5 | NOK 6.86:USD 1 | Jan 2016 – Jun 2016 |
At 30 June 2015, Lundin Petroleum had also entered into the following interest rate hedge contracts as follows:
| Borrowings expressed in MUSD |
Fixing of floating LIBOR Rate per annum |
Settlement period |
|---|---|---|
| 500 | 0.57% | 1 Apr 2013 – 31 Mar 2016 |
| 1,500 | 0.52% | 1 Jan 2015 – 31 Dec 2015 |
| 1,500 | 1.50% | 1 Jan 2016 – 31 Mar 2016 |
| 2,000 | 1.50% | 1 Apr 2016 – 31 Dec 2016 |
| 1,500 | 2.32% | 1 Jan 2017 – 31 Dec 2017 |
| 1,000 | 3.06% | 1 Jan 2018 – 31 Dec 2018 |
Under IAS 39, 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.
For the preparation of the financial statements for the reporting period, the following currency exchange rates have been used.
| 30 Jun 2015 | 30 Jun 2014 | 31 Dec 2014 | ||||
|---|---|---|---|---|---|---|
| Average | Period end | Average | Period end | Average | Period end | |
| 1 USD equals NOK | 7.7508 | 7.8568 | 6.0399 | 6.1528 | 6.3011 | 7.4332 |
| 1 USD equals Euro | 0.8961 | 0.8937 | 0.7297 | 0.7322 | 0.7526 | 0.8236 |
| 1 USD equals Rouble | 57.8952 | 55.7288 | 35.0390 | 33.9566 | 38.3878 | 59.5808 |
| 1 USD equals SEK | 8.3722 | 8.2358 | 6.5338 | 6.7186 | 6.8457 | 7.7366 |
| Expressed in MUSD | Note | 1 Jan 2015– 30 Jun 2015 6 months |
1 Apr 2015– 30 Jun 2015 3 months |
1 Jan 2014– 30 Jun 2014 6 months |
1 Apr 2014– 30 Jun 2014 3 months |
1 Jan 2014– 31 Dec 2014 12 months |
|---|---|---|---|---|---|---|
| Revenue | 1 | 279.1 | 157.8 | 460.8 | 225.4 | 785.2 |
| Cost of sales | ||||||
| Production costs | 2 | -64.5 | -39.3 | -80.3 | -41.9 | -66.5 |
| Depletion and decommissioning costs | -106.7 | -63.6 | -68.8 | -33.7 | -131.6 | |
| Exploration costs | -106.9 | -61.5 | -129.2 | -2.3 | -386.4 | |
| Impairment costs of oil and gas properties |
– | – | – | – | -400.7 | |
| Gross profit | 3 | 1.0 | -6.6 | 182.5 | 147.5 | -200.0 |
| General, administration and | ||||||
| depreciation expenses | -24.4 | -13.1 | -33.7 | -13.3 | -52.2 | |
| Operating profit | -23.4 | -19.7 | 148.8 | 134.2 | -252.2 | |
| Result from financial investments | ||||||
| Finance income | 4 | 1.3 | 0.4 | 1.0 | -26.4 | 1.8 |
| Finance costs | 5 | -225.0 | 1.1 | -38.5 | -26.3 | -421.8 |
| -223.7 | 1.5 | -37.5 | -52.7 | -420.0 | ||
| Share of the result of joint ventures accounted for using |
-12.9 | -12.8 | -12.9 | |||
| the equity method | – | – | ||||
| Profit before tax | -247.1 | -18.2 | 98.4 | 68.7 | -685.1 | |
| Income tax | 6 | 76.1 | 78.1 | -97.6 | -71.1 | 253.2 |
| Net result | -171.0 | 59.9 | 0.8 | -2.4 | -431.9 | |
| Attributable to: | ||||||
| Owners of the Parent Company | -168.8 | 61.1 | 3.2 | -1.2 | -427.2 | |
| Non-controlling interest | -2.2 | -1.2 | -2.4 | -1.2 | -4.7 | |
| -171.0 | 59.9 | 0.8 | -2.4 | -431.9 | ||
| Earnings per share – USD1 | -0.55 | 0.20 | 0.01 | – | -1.38 | |
| Earnings per share fully diluted – USD1 | -0.54 | 0.20 | 0.01 | – | -1.38 |
1 Based on net result attributable to shareholders of the Parent Company.
| Expressed in MUSD | 1 Jan 2015– 30 Jun 2015 6 months |
1 Apr 2015– 30 Jun 2015 3 months |
1 Jan 2014– 30 Jun 2014 6 months |
1 Apr 2014– 30 Jun 2014 3 months |
1 Jan 2014– 31 Dec 2014 12 months |
|---|---|---|---|---|---|
| Net result | -171.0 | 59.9 | 0.8 | -2.4 | -431.9 |
| Other comprehensive income | |||||
| Items that may be subsequently reclassified to profit or loss: |
|||||
| Exchange differences foreign operations | -17.6 | 0.8 | -16.3 | -7.7 | -196.3 |
| Cash flow hedges | 18.5 | 64.1 | -10.1 | -39.1 | -148.7 |
| Available-for-sale financial assets | -0.6 | -0.3 | -2.0 | -0.9 | -15.3 |
| Other comprehensive income, net of tax | 0.3 | 64.6 | -28.4 | -47.7 | -360.3 |
| Total comprehensive income | -170.7 | 124.5 | -27.6 | -50.1 | -792.2 |
| Attributable to: | |||||
| Owners of the Parent Company | -170.2 | 124.8 | -23.5 | -50.6 | -766.7 |
| Non-controlling interest | -0.5 | -0.3 | -4.1 | 0.5 | -25.5 |
| -170.7 | 124.5 | -27.6 | -50.1 | -792.2 |
| Expressed in MUSD | Note | 30 June 2015 | 31 December 2014 |
|---|---|---|---|
| ASSETS | |||
| Non-current assets | |||
| Oil and gas properties | 7 | 4,659.4 | 4,182.6 |
| Other tangible fixed assets | 220.5 | 200.3 | |
| Financial assets | 8 | 29.3 | 37.0 |
| Deferred tax assets | 11.0 | 12.9 | |
| Other non-current assets | 9 | 136.8 | – |
| Total non-current assets | 5,057.0 | 4,432.8 | |
| Current assets | |||
| Inventories | 39.3 | 41.6 | |
| Trade and other receivables | 10 | 173.2 | 163.5 |
| Current tax assets | 348.5 | 373.6 | |
| Cash and cash equivalents | 93.0 | 80.5 | |
| Total current assets | 654.0 | 659.2 | |
| TOTAL ASSETS | 5,711.0 | 5,092.0 | |
| EQUITY AND LIABILITIES | |||
| Equity | |||
| Shareholders´ equity | 264.9 | 431.5 | |
| Non-controlling interest | 33.7 | 34.2 | |
| Total equity | 298.6 | 465.7 | |
| Liabilities Non-current liabilities |
|||
| Financial liabilities | 11 | 3,521.6 | 2,654.0 |
| Provisions | 12 | 335.4 | 288.0 |
| Deferred tax liabilities | 981.3 | 973.3 | |
| Derivative instruments | 14 | 29.5 | 33.9 |
| Other non-current liabilities | 30.9 | 29.1 | |
| Total non-current liabilities | 4,898.7 | 3,978.3 | |
| Current liabilities | |||
| Trade and other payables | 13 | 431.5 | 491.4 |
| Derivative instruments | 14 | 76.7 | 101.4 |
| Current tax liabilities | 2.2 | 1.8 | |
| Provisions | 12 | 3.3 | 53.4 |
| Total current liabilities | 513.7 | 648.0 | |
| Total liabilities | 5,412.4 | 4,626.3 | |
| TOTAL EQUITY AND LIABILITIES | 5,711.0 | 5,092.0 |
| Expressed in MUSD | 1 Jan 2015– 30 Jun 2015 6 months |
1 Apr 2015– 30 Jun 2015 3 months |
1 Jan 2014– 30 Jun 2014 6 months |
1 Apr 2014– 30 Jun 2014 3 months |
1 Jan 2014– 31 Dec 2014 12 months |
|---|---|---|---|---|---|
| Cash flows from operating activities | |||||
| Net result | -171.0 | 59.9 | 0.8 | -2.4 | -431.9 |
| Adjustments for: | |||||
| Exploration costs | 106.9 | 61.5 | 129.2 | 2.3 | 386.4 |
| Depletion, depreciation and amortisation | 108.9 | 64.7 | 71.3 | 35.0 | 136.2 |
| Current tax | -132.8 | -73.2 | -116.5 | -57.6 | -419.7 |
| Deferred tax | 56.7 | -4.9 | 214.1 | 128.7 | 166.5 |
| Impairment of oil and gas properties | – | – | – | – | 400.7 |
| Long-term incentive plans | 9.8 | 7.6 | 10.9 | 2.9 | 14.5 |
| Foreign currency exchange loss | 97.0 | -65.9 | 16.4 | 20.9 | 333.1 |
| Other | 47.0 | 27.5 | 28.9 | 43.9 | 16.0 |
| Interest received | 0.3 | 0.2 | 0.3 | 0.1 | 0.9 |
| Interest paid | -46.8 | -25.5 | -22.8 | -12.6 | -56.5 |
| Income taxes paid | 0.1 | 4.0 | -8.6 | -1.6 | -13.8 |
| Changes in working capital | -85.2 | -27.9 | 92.3 | 16.6 | 109.0 |
| Total cash flows from operating activities | -9.1 | 28.0 | 416.3 | 176.2 | 641.4 |
| Cash flows from investing activities | |||||
| Investment in oil and gas properties | -802.9 | -406.7 | -903.5 | -449.2 | -1,957.8 |
| Investment in other fixed assets | -32.4 | -10.5 | -80.4 | -31.3 | -124.9 |
| Disposal of bonds | – | – | 10.5 | – | 10.5 |
| Investment in other shares and participations | -3.7 | – | – | – | – |
| Share in result in associated company | – | – | – | – | 11.7 |
| Decommissioning costs paid | -4.1 | -3.9 | -0.4 | -0.3 | -1.2 |
| Other payments | -0.5 | -0.4 | -0.1 | -0.1 | -0.1 |
| Total cash flows from investing activities | -843.6 | -421.5 | -973.9 | -480.9 | -2,061.8 |
| Cash flows from financing activities | |||||
| Changes in long-term receivables | – | – | -0.1 | -0.1 | 9.8 |
| Changes in long-term liabilities | 864.8 | 439.3 | 576.2 | 280.4 | 1,419.2 |
| Financing fees paid | -3.1 | -3.1 | -20.7 | -0.1 | -20.7 |
| Purchase of own shares | – | – | -9.8 | – | -9.8 |
| Distributions | – | – | -0.1 | -0.1 | -0.1 |
| Total cash flows from financing activities | 861.7 | 436.2 | 545.5 | 280.1 | 1,398.4 |
| Change in cash and cash equivalents | 9.0 | 42.7 | -12.1 | -24.6 | -22.0 |
| Cash and cash equivalents at the beginning of the period |
80.5 | 51.9 | 82.4 | 94.9 | 82.4 |
| Currency exchange difference in cash and cash equivalents |
3.5 | -1.6 | 2.8 | 2.8 | 20.1 |
| Cash and cash equivalents at the end of the period |
93.0 | 93.0 | 73.1 | 73.1 | 80.5 |
| Expressed in MUSD | Share capital |
Additional paid-in capital/Other reserves |
Retained earnings |
Total | Non controlling interest |
Total equity |
|---|---|---|---|---|---|---|
| At 1 January 2014 | 0.5 | 358.1 | 848.4 | 1,207.0 | 59.8 | 1,266.8 |
| Comprehensive income | ||||||
| Net result | – | – | 3.2 | 3.2 | -2.4 | 0.8 |
| Other comprehensive income | – | -26.7 | – | -26.7 | -1.7 | -28.4 |
| Total comprehensive income | – | -26.7 | 3.2 | -23.5 | -4.1 | -27.6 |
| Transactions with owners | ||||||
| Purchase of own shares | – | -9.8 | – | -9.8 | – | -9.8 |
| Total transactions with owners | – | -9.8 | – | -9.8 | – | -9.8 |
| At 30 June 2014 | 0.5 | 321.6 | 851.6 | 1,173.7 | 55.7 | 1,229.4 |
| Comprehensive income | ||||||
| Net result | – | – | -430.4 | -430.4 | -2.3 | -432.7 |
| Other comprehensive income | – | -312.8 | – | -312.8 | -19.1 | -331.9 |
| Total comprehensive income | – | -312.8 | -430.4 | -743.2 | -21.4 | -764.6 |
| Transactions with owners | ||||||
| Distributions | – | – | – | – | -0.1 | -0.1 |
| Value of employee services | – | – | 1.0 | 1.0 | – | 1.0 |
| Total transaction with owners | – | – | 1.0 | 1.0 | -0.1 | 0.9 |
| At 31 December 2014 | 0.5 | 8.8 | 422.2 | 431.5 | 34.2 | 465.7 |
| Comprehensive income | ||||||
| Net result | – | – | -168.8 | -168.8 | -2.2 | -171.0 |
| Other comprehensive income | – | -1.4 | – | -1.4 | 1.7 | 0.3 |
| Total comprehensive income | – | -1.4 | -168.8 | -170.2 | -0.5 | -170.7 |
| Transactions with owners | ||||||
| Value of employee services | – | – | 3.6 | 3.6 | – | 3.6 |
| Total transaction with owners | – | – | 3.6 | 3.6 | – | 3.6 |
| At 30 June 2015 | 0.5 | 7.4 | 257.0 | 264.9 | 33.7 | 298.6 |
Attributable to owners of the Parent Company
In 2014 the Parent Company reduced its share capital with an amount of SEK 68,402.50 through the cancellation of 6,840,250 shares held in treasury. The reduction of the share capital was followed by a bonus issue of the same amount. The amounts were recognised against other reserves. In consequence the cancellation of shares did not impact the Company's share capital.
| Note 1. Revenue MUSD |
1 Jan 2015– 30 Jun 2015 6 months |
1 Apr 2015– 30 Jun 2015 3 months |
1 Jan 2014– 30 Jun 2014 6 months |
1 Apr 2014– 30 Jun 2014 3 months |
1 Jan 2014– 31 Dec 2014 12 months |
|---|---|---|---|---|---|
| Crude oil | 214.7 | 111.5 | 413.3 | 214.7 | 627.4 |
| Condensate | 0.3 | 0.2 | 1.8 | 0.7 | 3.0 |
| Gas | 45.6 | 22.3 | 68.2 | 31.9 | 114.6 |
| Net sales of oil and gas | 260.6 | 134.0 | 483.3 | 247.3 | 745.0 |
| Change in under/over lift position | 9.7 | 18.1 | -30.5 | -25.9 | 23.4 |
| Other revenue | 8.8 | 5.7 | 8.0 | 4.0 | 16.8 |
| Revenue | 279.1 | 157.8 | 460.8 | 225.4 | 785.2 |
| Note 2. Production costs MUSD |
1 Jan 2015– 30 Jun 2015 6 months |
1 Apr 2015– 30 Jun 2015 3 months |
1 Jan 2014– 30 Jun 2014 6 months |
1 Apr 2014– 30 Jun 2014 3 months |
1 Jan 2014– 31 Dec 2014 12 months |
|---|---|---|---|---|---|
| Cost of operations | 55.8 | 34.4 | 52.5 | 21.9 | 94.4 |
| Tariff and transportation expenses | 5.8 | 3.3 | 9.8 | 5.0 | 18.4 |
| Direct production taxes | 1.5 | 0.8 | 1.9 | 1.0 | 3.6 |
| Change in inventory position | -5.5 | -3.1 | -1.6 | -1.4 | -0.8 |
| Other | 6.9 | 3.9 | 17.7 | 15.4 | -49.1 |
| 64.5 | 39.3 | 80.3 | 41.9 | 66.5 |
| Note 3. Segment information MUSD |
1 Jan 2015– 30 Jun 2015 6 months |
1 Apr 2015– 30 Jun 2015 3 months |
1 Jan 2014– 30 Jun 2014 6 months |
1 Apr 2014– 30 Jun 2014 3 months |
1 Jan 2014– 31 Dec 2014 12 months |
|---|---|---|---|---|---|
| Norway | |||||
| Crude oil | 166.9 | 75.5 | 364.4 | 190.4 | 530.5 |
| Condensate | – | – | 1.1 | 0.3 | 1.7 |
| Gas | 18.9 | 9.2 | 36.9 | 17.6 | 58.8 |
| Net sales of oil and gas | 185.8 | 84.7 | 402.4 | 208.3 | 591.0 |
| Change in under/over lift position | 9.5 | 18.0 | -30.4 | -25.8 | 24.4 |
| Other revenue | 1.1 | 0.6 | 2.3 | 1.1 | 3.8 |
| Revenue | 196.4 | 103.3 | 374.3 | 183.6 | 619.2 |
| Production costs | -44.7 | -27.0 | -55.8 | -30.0 | -11.3 |
| Depletion and decommissioning costs | -65.3 | -32.1 | -46.4 | -22.6 | -88.5 |
| Exploration costs | -105.9 | -61.0 | -74.6 | -1.8 | -272.1 |
| Impairment costs of oil and gas properties | – | – | – | – | -400.7 |
| Gross profit | -19.5 | -16.8 | 197.5 | 129.2 | -153.4 |
| Note 3. Segment information cont. MUSD |
1 Jan 2015– 30 Jun 2015 6 months |
1 Apr 2015– 30 Jun 2015 3 months |
1 Jan 2014– 30 Jun 2014 6 months |
1 Apr 2014– 30 Jun 2014 3 months |
1 Jan 2014– 31 Dec 2014 12 months |
|---|---|---|---|---|---|
| France | |||||
| Crude oil | 33.3 | 21.5 | 48.8 | 24.3 | 96.8 |
| Net sales of oil and gas | 33.3 | 21.5 | 48.8 | 24.3 | 96.8 |
| Change in under/over lift position | 0.2 | 0.1 | 0.3 | 0.3 | -0.5 |
| Other revenue | 0.7 | 0.3 | 0.9 | 0.5 | 1.7 |
| Revenue | 34.2 | 21.9 | 50.0 | 25.1 | 98.0 |
| Production costs | -13.6 | -9.9 | -14.8 | -6.8 | -33.1 |
| Depletion and decommissioning costs | -8.3 | -4.2 | -8.6 | -4.3 | -16.9 |
| Exploration costs | -0.6 | -0.6 | – | – | -4.6 |
| Gross profit | 11.7 | 7.2 | 26.6 | 14.0 | 43.4 |
| Netherlands | |||||
| Crude oil | – | – | 0.1 | – | 0.1 |
| Condensate | 0.3 | 0.2 | 0.7 | 0.4 | 1.3 |
| Gas | 12.3 | 5.7 | 19.5 | 8.3 | 33.8 |
| Net sales of oil and gas | 12.6 | 5.9 | 20.3 | 8.7 | 35.2 |
| Change in under/over lift position | – | – | -0.4 | -0.4 | -0.5 |
| Other revenue | 0.9 | 0.5 | 1.0 | 0.5 | 2.2 |
| Revenue | 13.5 | 6.4 | 20.9 | 8.8 | 36.9 |
| Production costs | -5.8 | -3.0 | -7.6 | -4.0 | -16.8 |
| Depletion and decommissioning costs | -5.5 | -2.7 | -8.3 | -4.0 | -15.9 |
| Exploration costs | -0.4 | – | -0.5 | – | -1.4 |
| Gross profit | 1.8 | 0.7 | 4.5 | 0.8 | 2.8 |
| Malaysia | |||||
| Crude oil | 14.5 | 14.5 | – | – | – |
| Net sales of oil and gas | 14.5 | 14.5 | – | – | – |
| Other revenue | 3.5 | 3.5 | – | – | – |
| Revenue | 18.0 | 18.0 | – | – | – |
| Production costs | 1.6 | 1.6 | – | – | – |
| Depletion and decommissioning costs | -21.4 | -21.4 | – | – | – |
| Exploration costs | – | – | – | – | -14.4 |
| Gross profit | -1.8 | -1.8 | – | – | -14.4 |
| Indonesia | |||||
| Gas | 14.4 | 7.4 | 11.8 | 6.0 | 22.0 |
| Net sales of oil and gas | 14.4 | 7.4 | 11.8 | 6.0 | 22.0 |
| Other revenue | – | – | – | – | – |
| Revenue | 14.4 | 7.4 | 11.8 | 6.0 | 22.0 |
| Production costs | -2.0 | -1.0 | -2.1 | -1.1 | -5.4 |
| Depletion and decommissioning costs | -6.2 | -3.2 | -5.5 | -2.8 | -10.3 |
| Exploration costs | – | 0.1 | -54.0 | -0.4 | -94.2 |
| Gross profit | 6.2 | 3.3 | -49.8 | 1.7 | -87.9 |
| Note 3. Segment information cont. MUSD |
1 Jan 2015– 30 Jun 2015 6 months |
1 Apr 2015– 30 Jun 2015 3 months |
1 Jan 2014– 30 Jun 2014 6 months |
1 Apr 2014– 30 Jun 2014 3 months |
1 Jan 2014– 31 Dec 2014 12 months |
|---|---|---|---|---|---|
| Other | |||||
| Crude oil | – | – | – | – | – |
| Net sales of oil and gas | – | – | – | – | – |
| Other revenue | 2.6 | 0.8 | 3.8 | 1.9 | 9.1 |
| Revenue | 2.6 | 0.8 | 3.8 | 1.9 | 9.1 |
| Production costs | – | – | – | – | 0.1 |
| Depletion and decommissioning costs | – | – | – | – | – |
| Exploration costs | – | – | -0.1 | -0.1 | 0.3 |
| Gross profit | 2.6 | 0.8 | 3.7 | 1.8 | 9.5 |
| Total | |||||
|---|---|---|---|---|---|
| Crude oil | 214.7 | 111.5 | 413.3 | 214.7 | 627.4 |
| Condensate | 0.3 | 0.2 | 1.8 | 0.7 | 3.0 |
| Gas | 45.6 | 22.3 | 68.2 | 31.9 | 114.6 |
| Net sales of oil and gas | 260.6 | 134.0 | 483.3 | 247.3 | 745.0 |
| Change in under/over lift position | 9.7 | 18.1 | -30.5 | -25.9 | 23.4 |
| Other revenue | 8.8 | 5.7 | 8.0 | 4.0 | 16.8 |
| Revenue | 279.1 | 157.8 | 460.8 | 225.4 | 785.2 |
| Production costs | -64.5 | -39.3 | -80.3 | -41.9 | -66.5 |
| Depletion and decommissioning costs | -106.7 | -63.6 | -68.8 | -33.7 | -131.6 |
| Exploration costs | -106.9 | -61.5 | -129.2 | -2.3 | -386.4 |
| Impairment costs of oil and gas properties | – | – | – | – | -400.7 |
| Gross profit | 1.0 | -6.6 | 182.5 | 147.5 | -200.0 |
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 2015– 30 Jun 2015 6 months |
1 Apr 2015– 30 Jun 2015 3 months |
1 Jan 2014– 30 Jun 2014 6 months |
1 Apr 2014– 30 Jun 2014 3 months |
1 Jan 2014– 31 Dec 2014 12 months |
|---|---|---|---|---|---|
| Interest income | 0.3 | 0.2 | 0.6 | 0.2 | 1.2 |
| Foreign currency exchange gain, net | – | – | – | -26.9 | – |
| Guarantee fees | 1.0 | 0.2 | 0.3 | 0.2 | 0.5 |
| Other | – | – | 0.1 | 0.1 | 0.1 |
| 1.3 | 0.4 | 1.0 | -26.4 | 1.8 |
| Note 5. Finance costs MUSD |
1 Jan 2015– 30 Jun 2015 6 months |
1 Apr 2015– 30 Jun 2015 3 months |
1 Jan 2014– 30 Jun 2014 6 months |
1 Apr 2014– 30 Jun 2014 3 months |
1 Jan 2014– 31 Dec 2014 12 months |
|---|---|---|---|---|---|
| Interest expense | 27.8 | 16.0 | 6.8 | 4.9 | 21.1 |
| Foreign currency exchange loss, net | 176.7 | -27.3 | 8.8 | 8.8 | 356.3 |
| Result on interest rate hedge settlement | 3.5 | 1.7 | 1.0 | 0.5 | 2.4 |
| Unwinding of site restoration discount | 4.8 | 2.5 | 3.6 | 1.8 | 7.0 |
| Amortisation of deferred financing fees | 6.1 | 3.2 | 6.1 | 3.3 | 12.6 |
| Loan facility commitment fees | 5.2 | 2.2 | 11.4 | 6.5 | 21.4 |
| Other | 0.9 | 0.6 | 0.8 | 0.5 | 1.0 |
| 225.0 | -1.1 | 38.5 | 26.3 | 421.8 |
| Note 6. Income tax MUSD |
1 Jan 2015– 30 Jun 2015 6 months |
1 Apr 2015– 30 Jun 2015 3 months |
1 Jan 2014– 30 Jun 2014 6 months |
1 Apr 2014– 30 Jun 2014 3 months |
1 Jan 2014– 31 Dec 2014 12 months |
|---|---|---|---|---|---|
| Current tax | -132.8 | -73.2 | -116.5 | -57.6 | -419.7 |
| Deferred tax | 56.7 | -4.9 | 214.1 | 128.7 | 166.5 |
| -76.1 | -78.1 | 97.6 | 71.1 | -253.2 |
| MUSD | 30 Jun 2015 | 31 Dec 2014 |
|---|---|---|
| Norway | 3,342.6 | 2,960.7 |
| France | 199.5 | 210.1 |
| Netherlands | 32.6 | 38.6 |
| Malaysia | 535.1 | 428.3 |
| Indonesia | 39.6 | 43.9 |
| Russia | 510.0 | 501.0 |
| 4,659.4 | 4,182.6 |
| MUSD | 30 Jun 2015 | 31 Dec 2014 |
|---|---|---|
| Other shares and participations | 7.6 | 4.7 |
| Brynhild operating cost share | 20.0 | 31.0 |
| Other | 1.7 | 1.3 |
| 29.3 | 37.0 |
| MUSD | 30 Jun 2015 | 31 Dec 2014 |
|---|---|---|
| Corporate tax | 136.8 | – |
| 136.8 | – |
| MUSD | 30 Jun 2015 | 31 Dec 2014 |
|---|---|---|
| Trade receivables | 53.0 | 40.3 |
| Underlift | 13.0 | 3.6 |
| Joint operations debtors | 23.0 | 49.1 |
| Prepaid expenses and accrued income | 44.8 | 41.5 |
| Brynhild operating cost share | 22.5 | 21.6 |
| Other | 16.9 | 7.4 |
| 173.2 | 163.5 |
| MUSD | 30 Jun 2015 | 31 Dec 2014 |
|---|---|---|
| Bank loans | 3,553.0 | 2,690.0 |
| Capitalised financing fees | -31.4 | -36.0 |
| 3,521.6 | 2,654.0 |
| Note 12. Provisions MUSD |
30 Jun 2015 | 31 Dec 2014 |
|---|---|---|
| Non-current: | ||
| Site restoration | 324.1 | 274.1 |
| Long-term incentive plans | 1.0 | 1.8 |
| Farm-in payment | 5.3 | 7.5 |
| Other | 5.0 | 4.6 |
| 335.4 | 288.0 | |
| Current: | ||
| Farm-in payment | – | 48.5 |
| Long-term incentive plans | 3.3 | 4.9 |
| 3.3 | 53.4 | |
| 338.7 | 341.4 |
| MUSD | 30 Jun 2015 | 31 Dec 2014 |
|---|---|---|
| Trade payables | 27.3 | 23.9 |
| Overlift | – | – |
| Joint operations creditors and accrued expenses | 315.8 | 383.5 |
| Other accrued expenses | 41.1 | 46.1 |
| Short-term bank loans | 35.6 | – |
| Long-term incentive plans | – | 28.2 |
| Other | 11.7 | 9.7 |
| 431.5 | 491.4 |
For financial instruments measured at fair value in the balance sheet, the following fair value measurement hierarchy is used:
– Level 1: based on quoted prices in active markets;
– Level 2: based on inputs other than quoted prices as within level 1, that are either directly or indirectly observable;
– Level 3: based on inputs which are not based on observable market data.
Based on this hierarchy, financial instruments measured at fair value can be detailed as follows:
| 30 June 2015 MUSD |
Level 1 | Level 2 | Level 3 |
|---|---|---|---|
| Assets | |||
| Cash and cash equivalents | 93.0 | – | – |
| Financial assets | 29.3 | – | – |
| 122.3 | – | – | |
| Liabilities | |||
| Derivative instruments – non-current | – | 29.5 | – |
| Derivative instruments – current | – | 76.7 | – |
| – | 106.2 | – |
| 31 December 2014 MUSD |
Level 1 | Level 2 | Level 3 |
|---|---|---|---|
| Assets | |||
| Cash and cash equivalents | 80.5 | – | – |
| Financial assets | 37.0 | – | – |
| 117.5 | – | – | |
| Liabilities | |||
| Derivative instruments – non-current | – | 33.9 | – |
| Derivative instruments – current | – | 101.4 | – |
| – | 135.3 | – |
There were no transfers between the levels during the year.
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.
| Expressed in MSEK | 1 Jan 2015– 30 Jun 2015 6 months |
1 Apr 2015– 30 Jun 2015 3 months |
1 Jan 2014– 30 Jun 2014 6 months |
1 Apr 2014– 30 Jun 2014 3 months |
1 Jan 2014– 31 Dec 2014 12 months |
|---|---|---|---|---|---|
| Revenue | 7.5 | 0.8 | 6.6 | 5.5 | 9.2 |
| General and administration expenses | -50.6 | -24.9 | -84.5 | -42.8 | -144.9 |
| Operating profit | -43.1 | -24.1 | -77.9 | -37.3 | -135.7 |
| Result from financial investments | |||||
| Finance income | 2.5 | 0.7 | 1.8 | 1.0 | 209.9 |
| Finance costs | – | – | -1.8 | -1.3 | -1.9 |
| 2.5 | 0.7 | – | -0.3 | 208.0 | |
| Profit before tax | -40.6 | -23.4 | -77.9 | -37.6 | 72.3 |
| Income tax | – | – | – | – | 36.4 |
| Net result | -40.6 | -23.4 | -77.9 | -37.6 | 108.7 |
| Expressed in MSEK | 1 Jan 2015– 30 Jun 2015 6 months |
1 Apr 2015– 30 Jun 2015 3 months |
1 Jan 2014– 30 Jun 2014 6 months |
1 Apr 2014– 30 Jun 2014 3 months |
1 Jan 2014– 31 Dec 2014 12 months |
|---|---|---|---|---|---|
| Net result | -40.6 | -23.4 | -77.9 | -37.6 | 108.7 |
| Other comprehensive income | – | – | – | – | – |
| Total comprehensive income | -40.6 | -23.4 | -77.9 | -37.6 | 108.7 |
| Attributable to: | |||||
| Shareholders of the Parent Company | -40.6 | -23.4 | -77.9 | -37.6 | 108.7 |
| -40.6 | -23.4 | -77.9 | -37.6 | 108.7 |
| Expressed in MSEK | 30 Jun 2015 | 31 Dec 2014 |
|---|---|---|
| ASSETS | ||
| Non-current assets | ||
| Shares in subsidiaries | 7,871.8 | 7,871.8 |
| Other tangible fixed assets | 0.2 | 0.2 |
| Total non-current assets | 7,872.0 | 7,872.0 |
| Current assets | ||
| Receivables | 21.0 | 16.7 |
| Cash and cash equivalents | 2.9 | 1.8 |
| Total current assets | 23.9 | 18.5 |
| TOTAL ASSETS | 7,895.9 | 7,890.5 |
| SHAREHOLDERS´EQUITY AND LIABILITIES | ||
| Shareholders´ equity including net result for the period | 7,819.9 | 7,860.5 |
| Non-current liabilities | ||
| Provisions | 0.3 | 0.3 |
| Total non-current liabilities | 0.3 | 0.3 |
| Current liabilities | ||
| Current liabilities | 8.3 | 16.2 |
| Payables to group companies | 67.4 | 13.5 |
| Total current liabilities | 75.7 | 29.7 |
| Total liabilities | 76.0 | 30.0 |
| TOTAL EQUITY AND LIABILITIES | 7,895.9 | 7,890.5 |
| Pledged assets | 7,578.2 | 8,717.8 |
| Expressed in MSEK | 1 Jan 2015– 30 Jun 2015 |
1 Apr 2015– 30 Jun 2015 |
1 Jan 2014– 30 Jun 2014 |
1 Apr 2014– 30 Jun 2014 |
1 Jan 2014– 31 Dec 2014 |
|---|---|---|---|---|---|
| 6 months | 3 months | 6 months | 3 months | 12 months | |
| Cash flow from operations | |||||
| Net result | -40.6 | -23.4 | -77.9 | -37.6 | 108.7 |
| Adjustment for non-cash related items | 0.1 | 0.8 | 0.1 | 0.1 | -36.7 |
| Changes in working capital | 41.9 | 18.5 | -12.0 | -5.8 | 11.0 |
| Total cash flow from operations | 1.4 | -4.1 | -89.8 | -43.3 | 83.0 |
| Cash flow from investments | |||||
| Change in other fixed assets | – | – | – | – | -0.1 |
| Total Cash flow from investments | – | – | – | – | -0.1 |
| Cash flow from financing | |||||
| Change in long-term liabilities | – | – | 153.9 | 45.9 | -21.7 |
| Purchase of own shares | – | – | -62.2 | – | -62.2 |
| Total cash flow from financing | – | – | 91.7 | 45.9 | -83.9 |
| Change in cash and cash equivalents | 1.4 | -4.1 | 1.9 | 2.6 | -1.0 |
| Cash and cash equivalents at the beginning | |||||
| of the period | 1.8 | 7.1 | 2.6 | 1.9 | 2.6 |
| Currency exchange difference in cash and cash equivalents |
-0.3 | -0.1 | 0.1 | 0.1 | 0.2 |
| Cash and cash equivalents at the end of the | |||||
| period | 2.9 | 2.9 | 4.6 | 4.6 | 1.8 |
| Restricted equity | Unrestricted equity | |||||
|---|---|---|---|---|---|---|
| Expressed in MSEK | Share capital |
Statutory reserve |
Other reserves |
Retained earnings |
Total | Total equity |
| Balance at 1 January 2014 | 3.2 | 861.3 | 2,357.5 | 4,592.0 | 6,949.5 | 7,814.0 |
| Total comprehensive income | – | – | – | -77.9 | -77.9 | -77.9 |
| Transactions with owners | ||||||
| Purchase of own shares | – | – | -62.2 | – | -62.2 | -62.2 |
| Total transactions with owners | – | – | -62.2 | – | -62.2 | -62.2 |
| Balance at 30 June 2014 | 3.2 | 861.3 | 2,295.3 | 4,514.1 | 6,809.4 | 7,673.9 |
| Total comprehensive income | – | – | – | 186.6 | 186.6 | 186.6 |
| Balance at 31 December 2014 | 3.2 | 861.3 | 2,295.3 | 4,700.7 | 6,996.0 | 7,860.5 |
| Total comprehensive income | – | – | – | -40.6 | -40.6 | -40.6 |
| Balance at 30 June 2015 | 3.2 | 861.3 | 2,295.3 | 4,660.1 | 6,955.4 | 7,819.9 |
In 2014 the Company reduced its share capital with an amount of SEK 68,402.50 through the cancellation of 6,840,250 shares held in treasury. The reduction of the share capital was followed by a bonus issue of the same amount. The amounts were recognised against other reserves. In consequence the cancellation of shares did not impact the Company's share capital.
| Financial data (MUSD) | 1 Jan 2015– 30 Jun 2015 6 months |
1 Apr 2015– 30 Jun 2015 3 months |
1 Jan 2014– 30 Jun 2014 6 months |
1 Apr 2014– 30 Jun 2014 3 months |
1 Jan 2014– 31 Dec 2014 12 months |
|---|---|---|---|---|---|
| Revenue | 279.1 | 157.8 | 460.8 | 225.4 | 785.2 |
| EBITDA | 192.4 | 106.5 | 349.3 | 171.5 | 671.3 |
| Net result | -171.0 | 59.9 | 0.8 | -2.4 | -431.9 |
| Operating cash flow | 347.3 | 191.6 | 497.0 | 241.0 | 1,138.5 |
| Data per share (USD) | |||||
| Shareholders' equity per share | 0.86 | 0.86 | 3.80 | 3.80 | 1.40 |
| Operating cash flow per share | 1.12 | 0.62 | 1.60 | 0.78 | 3.68 |
| Cash flow from operations per share | -0.03 | 0.09 | 1.34 | 0.57 | 2.07 |
| Earnings per share | -0.55 | 0.20 | 0.01 | 0.00 | -1.38 |
| Earnings per share fully diluted | -0.54 | 0.20 | 0.01 | 0.00 | -1.38 |
| EBITDA per share | 0.62 | 0.34 | 1.13 | 0.55 | 2.17 |
| Dividend per share | – | – | – | – | – |
| Number of shares issued at period end | 311,070,330 | 311,070,330 | 311,070,330 | 311,070,330 | 311,070,330 |
| Number of shares in circulation at period end | 309,070,330 | 309,070,330 | 309,070,330 | 309,070,330 | 309,070,330 |
| Weighted average number of shares for the period | 309,070,330 | 309,070,330 | 310,045,004 | 310,682,627 | 309,170,986 |
| Weighted average number of shares for the period fully diluted |
309,678,433 | 309,678,433 | 310,045,004 | 310,682,627 | 309,475,038 |
| Share price | |||||
| Quoted price at period end (SEK) | 142.00 | 142.00 | 135.20 | 135.20 | 112.40 |
| Key ratios | |||||
| Return on equity (%) | -45 | 16 | 0 | 0 | -50 |
| Return on capital employed (%) | -1 | -1 | 4 | 4 | -11 |
| Net debt/equity ratio (%) | 1,320 | 1,320 | 151 | 151 | 605 |
| Equity ratio (%) | 5 | 5 | 23 | 23 | 9 |
| Share of risk capital (%) | 22 | 22 | 47 | 47 | 28 |
| Interest coverage ratio | -1 | -2 | 15 | 20 | -13 |
| Operating cash flow/interest ratio | 11 | 11 | 63 | 45 | 49 |
| Yield | – | – | – | – | – |
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.
Operating cash flow: Revenue less production costs and less current taxes.
Shareholders' equity per share: Shareholders' equity divided by the number of shares in circulation at period end.
Operating cash flow per share: Revenue less production costs and less current taxes divided by the weighted average number of shares for the period.
Cash flow from operations per share: Cash flow from operations in accordance with the consolidated statement of 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 the dilution effect of the awards outstanding under the Group's performance based incentive-plan.
EBITDA per share: EBITDA divided by the weighted average number of shares 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 the dilution effect of the awards outstanding under the Group's performance based incentive-plan.
Return on equity: Net result divided by average total equity.
Return on capital employed: Income before tax plus interest expenses plus/less 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.
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 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 charge for the period.
Yield: dividend per share in relation to quoted share price at the end of the financial period.
The Board of Directors and the President and CEO certify that the financial report for the six months ended 30 June 2015 gives a fair view of the performance of the business, position and profit or loss of the Company and the Group, and describes the principal risks and uncertainties that the Company and the companies in the Group face.
Stockholm, 5 August 2015
Ian H. Lundin Chairman
C. Ashley Heppenstall President and CEO
Peggy Bruzelius
Lukas H. Lundin William A. Rand Grace Reksten Skaugen
Magnus Unger Cecilia Vieweg
We have reviewed this report for the period 1 January 2015 to 30 June 2015 for Lundin Petroleum AB (publ). The board of directors and the President and CEO are responsible for the preparation and presentation of this interim report in accordance with IAS 34 and the Swedish Annual Accounts Act. Our responsibility is to express a conclusion on this interim report based on our review.
We conducted our review in accordance with the Swedish Standard on Review Engagements ISRE 2410, Review of Interim Report Performed by the Independent Auditor of the Entity. A review consists of making inquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing, ISA, and other generally accepted auditing standards in Sweden. The procedures performed in a review do not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.
Based on our review, nothing has come to our attention that causes us to believe that the interim report is not prepared, in all material respects, in accordance with IAS 34 and the Swedish Annual Accounts Act, regarding the Group, and with the Swedish Annual Accounts Act, regarding the Parent Company.
Stockholm, 5 August 2015
PricewaterhouseCoopers AB
Johan Rippe Authorised Public Accountant Lead Auditor
Johan Malmqvist Authorised Public Accountant
The AGM will be held on 12 May 2016 in Stockholm, Sweden.
For further information, please contact:
Maria Hamilton Teitur Poulsen [email protected] Tel: +41 22 595 10 00 Tel: +41 22 595 10 00 Tel: +46 8 440 54 50 Mobile: +41 79 63 53 641
Head of Corporate Communications VP Corporate Planning & Investor Relations
This information has been made public in accordance with the Securities Market Act (SFS 2007:528) and/or the Financial Instruments Trading Act (SFS 1991:980).
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 "forwardlooking 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 F +46-8-440 54 59 [email protected]
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