Quarterly Report • May 7, 2018
Quarterly Report
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QUARTERLY REPORT FOR AKER BP ASA
Aker BP (OSE:AKERBP) reported total income of USD 890 million and operating profit of USD 472 million for the first quarter 2018. Net profit was USD 161 million and earnings per share were USD 0.45. The company paid a dividend of USD 0.3124 (NOK 2.40) per share in the quarter.
Total income increased to USD 890 million driven by record high production of 158.6 thousand barrels of oil equivalents per day ("mboepd") and higher oil prices. Production volumes increased primarily due to the acquisition of Hess Norge in late December 2017. Production costs amounted to USD 12.1 per barrel oil equivalents ("boe"), in line with the company's guidance of around USD 12 per boe for 2018.
Exploration spend totalled USD 80 million, of which USD 55 million was expensed. Three exploration wells were drilled in the quarter, resulting in a 30-60 mmboe oil discovery on the Frosk prospect and a positive appraisal of the Ærfugl field. The company was also awarded 23 new licences, of which 14 with Aker BP as operator, in the 2017 APA licensing round.
Net profit amounted to USD 161 million in the first quarter, reflecting operating profit (EBIT) of USD 472 million, net financial expenses of USD 47 million and USD 264 million in taxes.
Cash flow to investment activities was USD 378 million. Investments in fixed assets amounted to USD 257 million, mainly related to the fields Johan Sverdrup, Valhall and Tambar. Abandonment expenditures were USD 82 million, driven by the ongoing campaign to plug and abandon old wells on the Valhall field.
The company's net interest-bearing debt was USD 3.0 billion at the end of the first quarter. Total available liquidity was USD 3.5 billion. During the first quarter, Aker BP issued a new USD 500 million senior note due in 2025. The proceeds were used to reduce the drawn amount under the company's reserve-based lending ("RBL") facility.
In February, the company paid a quarterly dividend of USD 112.5 million or USD 0.3124 per share, and the Board has resolved to pay the same amount in dividends in May. The plan is to maintain this level for the remaining quarters of 2018, implying total annual dividends of USD 450 million. The Board's ambition is to increase the annual dividends by USD 100 million per year from 2019 to 2021.
The Johan Sverdrup Phase 1 development project is progressing according to plan, and the capex estimate was further reduced in the first quarter. The operator's new capex estimate is NOK 88 billion (nominal at project currency), down NOK 4 billion from the previous update, and the break-even oil price for the project is now estimated to be below USD 15 per barrel.
The Aker BP-operated field developments of Ærfugl, Valhall Flank West and Skogul have all been approved by the authorities and are progressing according to plan. During the first quarter, new production wells were brought on stream at the Alvheim and Tambar fields. The Valhall Flank North Water Injection project was also sanctioned in the quarter.
The NOAKA area represents a significant new growth opportunity for Aker BP, with gross resources of more than 500 mmboe. Two different development concepts have been proposed, one involving unmanned platforms with host support, and one involving a central hub platform.
The premise defined by the authorities, and confirmed in recent dialogue, has been that a development should capture all discovered resources in the area and facilitate for future tie-ins of new discoveries.
Aker BP recommends developing NOAKA with a new hub platform, which would ensure production from all discoveries in the area as well as higher resource recovery and socio-economic benefits than the alternative. NOAKA will be a new major field development on the Norwegian Continental Shelf ("NCS"). Building on the positive experience from the alliance model, the ambition is to set a new standard in terms of cost per installed ton on the NCS. The company is targeting a concept selection in 2018.
Aker BP's ambition is to make NOAKA the first energy positive zero emissions field development on the NCS, powered by electricity from shore combined with offshore wind. Aker BP aims to build further on its Ivar Aasen experience with digitalization and automation to achieve maximum operational efficiency and the highest safety standards.
Forward-looking statements in this report reflect current views about future events and are, by their nature, subject to significant risks and uncertainties because they relate to events and depend on circumstances that will occur in the future.
All figures are presented in USD unless otherwise stated, and figures in brackets apply to the corresponding period in the previous year.
| Unit | Q1 2018 | Q1 2017 | 2018 YTD | 2017 YTD | |
|---|---|---|---|---|---|
| Operating income | USDm | 890 | 646 | 890 | 646 |
| EBITDA | USDm | 658 | 487 | 658 | 487 |
| Net result | USDm | 161 | 69 | 161 | 69 |
| Earnings per share (EPS) | USD | 0.45 | 0.20 | 0.45 | 0.20 |
| Production cost per barrel | USD/boe | 12.1 | 9.2 | 12.1 | 9.2 |
| Depreciation per barrel | USD/boe | 13.0 | 14.1 | 13.0 | 14.1 |
| Cash flow from operations | USDm | 600 | 438 | 600 | 438 |
| Cash flow from investments | USDm | -378 | -270 | -378 | -270 |
| Total assets | USDm | 11 985 | 9 337 | 11 985 | 9 337 |
| Net interest-bearing debt (book value) | USDm | 3 048 | 2 330 | 3 048 | 2 330 |
| Cash and cash equivalents | USDm | 38 | 183 | 38 | 183 |
| Unit | Q1 2018 | Q1 2017 | 2018 YTD | 2017 YTD | |
|---|---|---|---|---|---|
| Alvheim, incl. Boa (65%) | boepd | 40 516 | 64 383 | 40 516 | 64 383 |
| Bøyla (65%) | boepd | 3 235 | 4 545 | 3 235 | 4 545 |
| Gina Krog (3.3%) | boepd | 1 505 | - | 1 505 | - |
| Hod (90%) (37.5% until Q4 17) | boepd | 1 016 | 568 | 1 016 | 568 |
| Ivar Aasen (34.8%) | boepd | 24 421 | 15 003 | 24 421 | 15 003 |
| Skarv (23.4%) | boepd | 27 092 | 31 608 | 27 092 | 31 608 |
| Tambar / Tambar East (55.0%/46.2%) | boepd | 1 611 | 2 059 | 1 611 | 2 059 |
| Ula (80%) | boepd | 6 486 | 6 183 | 6 486 | 6 183 |
| Valhall (90%) (36.0% until Q4 17) | boepd | 33 500 | 14 796 | 33 500 | 14 796 |
| Vilje (46.9%) | boepd | 5 090 | 5 604 | 5 090 | 5 604 |
| Volund (65%) | boepd | 14 109 | 526 | 14 109 | 526 |
| Other | boepd | 71 | 65 | 71 | 65 |
| SUM | boepd | 158 649 | 145 338 | 158 649 | 145 338 |
| Oil price realised | USD/bbl | 69 | 54 | 69 | 54 |
| Gas price realised | USD/scm | 0.28 | 0.21 | 0.28 | 0.21 |
| (USD million) | Q1 2018 | Q1 2017 |
|---|---|---|
| Operating income | 890 | 646 |
| EBITDA | 658 | 487 |
| EBIT | 472 | 273 |
| Pre-tax profit/loss | 425 | 227 |
| Net profit | 161 | 69 |
| EPS (USD) | 0.45 | 0.20 |
Total income in the first quarter was USD 890 (646) million, higher than the first quarter 2017 due to increased production and higher realized prices. Petroleum revenues amounted to USD 892 (647) million, while other income was USD -2 (-1) million, primarily related to realized and unrealized gains and losses on commodity hedges.
Exploration expenses amounted to USD 55 (30) million in the quarter, reflecting dry hole costs, seismic costs, field evaluation costs, area fees and G&G activities. Production costs were USD 173 (121) million, equating to 12.1 (9.2) USD/ boe. The increase from the first quarter 2017 is mainly driven by increased interest in Valhall and Hod, and by a generally higher activity level. Other operating expenses amounted to USD 4 (8) million.
Depreciation amounted to USD 185 (184) million, corresponding to 13.0 (14.1) USD/boe. No impairments were recorded in the quarter, compared to USD 30 million in the first quarter 2017.
The company recorded operating profit of USD 472 (273) million in the first quarter, higher than the first quarter 2017, mainly driven by increased production and higher realized prices.
Net profit for the period was USD 161 (69) million after net financial expenses of USD 47 (47) million and tax expenses of USD 264 (158) million, or 62 percent. Earnings per share were USD 0.45 (0.20).
| (USD million) | Q1 2018 | Q1 2017 |
|---|---|---|
| Goodwill | 1 860 | 1 818 |
| PP&E | 5 665 | 4 600 |
| Cash & cash equivalents | 38 | 183 |
| Total assets | 11 985 | 9 337 |
| Equity | 3 110 | 2 455 |
| Interest-bearing debt | 3 048 | 2 330 |
At the end of first quarter 2018, total intangible assets amounted to USD 3,852 (3,482) million, of which goodwill was USD 1,860 (1,818) million.
Property, plant and equipment increased to USD 5,665 (4,600) million. The main driver for the increase was the acquisition of Hess Norge which took place in the fourth quarter 2017, in addition to ordinary investments in development projects. Current tax receivables amounted to USD 1,666 (395) million at the end of the quarter, and is mainly related to a tax loss assumed through the Hess Norge acquisition, which is expected to be disbursed in the second half of 2018.
Cash and cash equivalents were USD 38 (183) million at the end of the quarter. Total assets were USD 11,985 (9,337) million.
Equity amounted to USD 3,110 (2,455) million at the end of the first quarter, corresponding to an equity ratio of 26 (26) percent. The increase was caused by total comprehensive income of USD 466 million and an equity issue with net proceeds of USD 489 million, adjusted for USD 300 million in dividend payments in the period from 1 April 2017 to 31 March 2018.
Deferred tax liabilities amounted to USD 1,357 (1,164) million and are detailed in note 7 to the financial statements.
In March, the company priced a new notes offering of USD 500 million aggregate principal amount of 5.875% senior notes due in 2025 at par. Interest is payable semi-annually.
Gross interest-bearing debt was USD 3,086 (2,513) million, consisting of the DETNOR02 bond of USD 243 million, the AKERBP Senior Note 2017 (17/22) of USD 392 million, the AKERBP Senior Note 2018 (18/25) of USD 492 million, the Reserve Based Lending ("RBL") facility of USD 460 million and a bank term loan of USD 1,498 million. The latter will be repaid when the previously mentioned tax loss from Hess Norge is disbursed.
| (USD million) | Q1 2018 | Q1 2017 |
|---|---|---|
| Cash flow from operations | 600 | 438 |
| Cash flow from investments | -378 | -270 |
| Cash flow from financing | -435 | -98 |
| Net change in cash & cash eq. | -213 | 70 |
| Cash and cash eq. EOQ | 38 | 183 |
Net cash flow from operating activities was USD 600 (438) million. The change was mainly caused by increased profit before tax, which was driven by increased production and higher realized prices.
Net cash flow to investment activities was USD 378 (270) million, of which investments in fixed assets amounted to USD 257 (232) million for the quarter, mainly related to the fields Johan Sverdrup, Valhall and Tambar. Investments in intangible assets including capitalized exploration were USD 39 (30) million in the quarter. Payments for decommissioning activities amounted to USD 82 (8) million in the quarter, mainly related to plugging and abandonment of depleted wells at Valhall.
Net cash flow from financing activities totalled USD -435 (-98) million, reflecting USD 492 million in net proceeds from the issuance of a new USD note, repayment of USD 815 million on the RBL and dividend disbursements of USD 112.5 million during the quarter.
At the end of the first quarter, the company had total available liquidity of USD 3.5 (2.6) billion, comprising of cash and cash equivalents of USD 38 (183) million and undrawn credit facilities of USD 3,485 (2,416) million.
On 15 March, the company priced a notes offering of USD 500 million aggregate principal amount of 5.875 percent senior unsecured notes due 2025 at par. Interest will be payable semi-annually. The offering was closed on 22 March 2017.
The company seeks to reduce the risk related to foreign exchange rates, interest rates and commodity prices through hedging instruments. The company actively manages its exposures through a mix of forward contracts and options.
The company has bought Brent put options for 2018 at strike prices from USD 50 to USD 60 per barrel. Total hedging volume is around 22 percent of estimated oil production for 2018, corresponding to approximately 78 percent of the undiscounted after-tax value.
A quarterly dividend of USD 112.5 million, corresponding to USD 0.3124 per share was disbursed on 14 February 2018.
At the Annual General Meeting in April 2018, the Board was authorized to approve the distribution of dividends based on the company's annual accounts for 2017 pursuant to section 8-2 (2) of the Norwegian Public Limited Companies Act.
The Board has proposed a dividend of USD 450 million in 2018 and stated a clear ambition to increase this by USD 100 million per year to 2021.
On 4 May 2018, the Board of Directors declared a quarterly dividend of USD 0.3124 per share, to be disbursed on or about 22 May 2018.
Aker BP produced 14.3 (13.1) mmboe in the first quarter of 2018, corresponding to 158.6 (145.3) mboepd. The average realized oil price was USD 69 (54) per barrel, while gas revenues were recognized at market value of USD 0.28 (0.21) per standard cubic metre (scm).
The producing fields Alvheim (65 percent), Volund (65 percent), Bøyla (65 percent) and Vilje (46.9 percent) are all tied back to the Alvheim FPSO.
First quarter production from the Alvheim area was 62.9 mboepd net to Aker BP, slightly down from the previous quarter due to ordinary decline and two unplanned plant shutdowns. Two new wells at the Boa drill centre were put in operation in the first quarter 2018, six weeks ahead of plan, and contributed positively to production volumes.
The production efficiency for the Alvheim area was 98 percent in the quarter.
The Valhall area consists of the producing fields Valhall (90 percent) and Hod (90 percent).
First quarter production from the Valhall area was 34.5 mboepd net to Aker BP. This represents an underlying reduction of approximately seven percent compared to the previous quarter, and was caused by two periods of adverse weather conditions with negative impact on regularity.
The 2018 IP drilling programme at Valhall consists of three new wells. The first of these wells is currently being stimulated and is planned to start production in the second quarter. The second well is currently being drilled, and is expected to start production in the third quarter. Meanwhile, the Maersk Invincible rig continued the successful P&A campaign at Valhall.
The production efficiency for the Valhall area was 84 percent in the quarter.
The Ula area consists of the producing fields Ula (80.0 percent), Tambar (55.0 percent) and Tambar East (46.2 percent). Tambar and Tambar East are tied back to the Ula facilities, together with the Repsol operated Blane field and the Faroe operated Oselvar field.
First quarter production from the Ula area was 8.1 mboepd net to Aker BP, 17 percent higher than in the previous quarter. The two new Tambar wells started production in March.
The installation of a new riser for the tie in of Oda to Ula has successfully been completed, and production from the Oselvar field has been terminated as part of the preparation for conversion of the production equipment on Ula from Oselvar to Oda.
The production efficiency for the Ula area was 63 percent in the quarter.
The Skarv area consists of the Skarv producing field (23.835 percent). In addition, production from the Ærfugl A-1 H well (previously named Snadd test producer) is included in the Skarv volumes.
First quarter production from the Skarv area was 27.1 mboepd net to Aker BP, up 27 percent compared to the previous quarter. At the beginning of fourth quarter 2017, three wells were shut in due to technical issues with the Xmas trees. One of these wells was successfully reinstated at the end of 2017 and has since been in production, contributing positively to the Skarv production. Plant uptime during the last quarter has also been high at 99.7 percent and thus contributed positively to the production volumes.
At the end of the first quarter, Aker BP initiated an operation to reinstate one of the two remaining shut-in wells during first half of 2018. The company is also planning to pull the x-mas tree from the last well and perform root cause analysis in order to prevent similar failures in the future.
The Ærfugl A1-H well was onstream throughout the quarter. The well was granted a permanent production permit as part of the approval of the Ærfugl PDO.
The production efficiency for the Skarv area was 94.4 percent in the quarter, mainly influenced by the before mentioned well failures which lowered the production efficiency by 4.6 percent.
The Ivar Aasen field (34.786 percent) is developed in coordination with the Edvard Grieg field, which provides Ivar Aasen with power, processing and export solutions.
Production from Ivar Aasen reached 24.4 mboepd net to Aker BP in the first quarter, representing an increase of four percent from the previous quarter. The operational efficiency was high, with an average plant availability of 98 percent. However, production was negatively impacted by Edvard Grieg and SAGE availability, resulting in a production efficiency of 89 percent in the quarter.
Two new water injection wells are planned to be drilled at Ivar Aasen this year, followed by an exploration well to test the Slengfehøgda prospect and appraise the Hanz discovery. The first of these wells was spudded in April.
The Gina Krog field (3.3 percent) started production on 30 June 2017. The field has been developed with a fixed platform with living quarters and processing facilities. The oil from Gina Krog is exported by shuttle tankers while gas is exported via the Sleipner platform.
Production from Gina Krog was 1.5 mboepd net to Aker BP in the first quarter.
The Petroleum Safety Authority Norway (PSA) has concluded its investigation of the fatal incident that took place on Maersk Interceptor on the Tambar field on 7 December 2017, and the incident investigation report was issued on the PSA's webpages on 3 May 2018. The report concludes that a raw water pump fell to sea as a consequence of the failure of a flat-braided sling used in a lifting operation. The lifting operation was part of the installation of a raw water pump. The incident resulted in one fatality and one person seriously injured.
Both Aker BP and Maersk Drilling support the findings of the PSA report, which are consistent with those of the internal Maersk Drilling investigation. In addition, Maersk Drilling and Aker BP have conducted industry knowledge transfer sessions in Norway and internationally. Both companies will continue to share the learnings in relevant industry forums.
Aker BP has conducted sessions on safety leadership for onshore and offshore leaders during the first quarter. Considerable work on standardization of critical offshore safety procedures has also been executed. The latter is an important part of the Aker BP HSE agenda on standardization and culture in the company.
Phase 1 of the Johan Sverdrup (11.5733 percent) development project is progressing according to plan towards production start-up by the end of 2019. Phase 1 consists of a field centre with four fixed platforms, three subsea templates, oil and gas export pipelines, power from shore and 36 production and injection wells.
At the end of the first quarter, approximately 84 percent of the Phase 1 facilities were complete. The riser platform modules arrived in Haugesund mid-April for installation of two platform cranes. Traditional heavy lift installation offshore of the riser platform modules was completed late April (Heerema). With this, the first of four topsides has been installed.
The onshore hook up and commissioning of the drilling platform at Aibel in Haugesund is progressing well, preparing for offshore installation in early June 2018 by Pioneering Spirit (Allseas).
After a successful completion of the eight pre-drilled production wells and a four well pilot/appraisal campaign for further improvement of reservoir definition, all the 10 planned pre-drilled water injection wells have been completed.
PDO for Phase 2 is scheduled for the second half of 2018. Phase 2 production start-up is expected in 2022. Phase 2 includes 28 additional production and injection wells in the peripheral parts of the field, increasing the total number of wells to 64.
Phase 2 also includes an increased production capacity on a fifth platform at the field centre, increasing the capacity from 440,000 to 660,000 barrels of oil per day. The front end engineering and design ("FEED") for the Phase 2 installations has been completed with a high engineering maturity level prior to the final investment decision. In April, a Letter of Intent was signed with Aibel for construction of the processing platform topside for phase 2 of the project. A letter of intent for field centre modifications was also signed with a joint venture of Aker Solutions and Kværner.
Phase 2 also includes increased power-from-shore capacity, which will allow Johan Sverdrup to supply the surrounding fields Ivar Aasen, Edvard Grieg and Gina Krog with power.
The operator's Phase 1 CAPEX estimate, last updated in the first quarter 2018, was NOK 88 billion (nominal at project currency), which is NOK 35 billion (28 percent) lower than at the time the PDO was submitted in 2015. The CAPEX estimate for Phase 2 is NOK 40 – 55 billion, which is approximately half the cost estimated for Phase 2 when the PDO for Phase 1 was submitted.
The operator estimates the Johan Sverdrup reserves to be between 2.1 and 3.1 billion barrels of oil equivalents (boe) and the full field break-even oil price to be below USD 20 per boe.
The Valhall Flank West project aims to continue the development of the Tor Formation on the western flank of the Valhall field, with planned start-up of operations in fourth quarter 2019. Valhall Flank West will be developed from a new Normally Unmanned Installation (NUI), tied back to the Valhall field centre for processing and export. Recoverable reserves are estimated at around 60 million barrels of oil equivalents. Gross investments for the development are estimated at NOK 5.5 billion in real terms.
The PDO for Valhall Flank West was approved in March 2018. Engineering has progressed according to plan and construction activities have started in Verdal. Preparation activities at the Valhall Central Complex are underway.
The Valhall Flank North Water Injection project aims to expand water injection capability to Valhall's northern drainage area, thus supporting Valhall production through enabling water injection to existing depleted areas and offering a potential for increasing the recovery from the reservoir by 7.8 mmboe gross. The project was sanctioned in first quarter 2018. The plan is to start drilling operations in fourth quarter 2018, and to start water injection in second quarter 2019 when pipelines and risers have been installed.
The North of Alvheim and Askja-Krafla (NOAKA) area consists of the discoveries Frigg Gamma Delta, Langfjellet, Frøy, Fulla, Frigg, Rind and Askja-Krafla. Gross resources in the area are estimated to be more than 500 mmboe.
Aker BP and the other partners have performed detailed studies of different development solutions for the NOAKA area. The premise defined by the authorities, and confirmed in recent dialogue, has been that a development should capture all discovered resources in the area and facilitate for future tie-ins of new discoveries.
These studies have resulted in two alternative development solutions. One solution involves two unmanned production platforms ("UPP") or similar concepts, supported from an existing host in the area. The other solution involves a new hub platform in the central part of the area, with processing and living quarters ("PQ").
Aker BP's recommendation is to develop the area with the PQ concept. This concept is the only alternative that allows for economic recovery of all discovered resources in the area, and provides higher resource recovery and socio-economic benefits than the alternative. The PQ concept also more is also the better alternative with regards to exploiting additional resources that may be discovered through future exploration.
Aker BP's ambition is to make NOAKA the first energy positive field development on the Norwegian Continental Shelf. The goal is full electrification and zero emissions, enabled by power from shore combined with offshore wind. Aker BP aims to build further on its Ivar Aasen experience with onshore control rooms and a high degree of digitalization and automation to achieve maximum operational efficiency and the highest safety standards.
The NOAKA PQ concept will be a new major field development on the Norwegian Continental Shelf. Building on the positive experience from the alliance model, the ambition is to set a new standard in terms of cost per installed ton on the NCS.
The company is targeting a concept selection in 2018.
Skogul (previously known as Storklakken) will be developed with a single multilateral production well tied back to the Vilje field, utilizing the existing pipeline from Vilje to the Alvheim FPSO. Recoverable reserves are estimated at around 10 mmboe gross, and total investments at NOK 1.5 billion in real terms. Production start is planned for the first quarter of 2020. The PDO was approved by Norwegian authorities in March 2018.
The production well at Skogul will be subsea production well number 35 in the Alvheim area. It represents Aker BP's continuous effort to maximize value and extend the economic life in the Alvheim area.
The PDO for the Ærfugl development was submitted in December 2017, and was approved by Norwegian authorities in April 2018. At the same time, the A-1H well which has previously been on test production was granted a permanent production permit.
Ærfugl will be developed in two phases. The first phase includes three new production wells in the southern part of the field tied into the Skarv FPSO via a trace heated pipe-in-pipe flowline, in addition to the existing A-1 H well. Production from the new wells is planned to begin late 2020.
The second phase is subject to further maturation, but the reference case includes two additional wells in the northern part of the field and one in Snadd Outer, located in PL212E (Aker BP 30 percent), all tied into the Skarv FPSO with an estimated production start in 2023. Other alternatives will also be considered in order to select the optimal concept.
The total remaining reserves for the full-field development are estimated to approximately 275 mmboe gross. Total investments in the project are estimated at NOK 8.5 billion (real terms) with NOK 4.5 billion in the first phase and NOK 4.0 billion in the second phase (reference case) respectively.
Aker BP has on behalf of the Ærfugl partners entered into field development contracts with Subsea 7 for Subsea Umbilical Riser Flowline (SURF) and with Aker Solutions for Subsea Production System (SPS). The Ærfugl project will be organized and executed according to Aker BP's alliance model.
Tambar is a satellite field to Ula. The Tambar development project is targeting gross reserves of 27 mmboe, which is expected to extend the economic life of the field to at least 2028. The project consists of two additional wells and gas lift. The new wells were completed and began producing late in the first quarter. Gas lift is scheduled to commence in the fourth quarter pending completion of the remaining facilities modifications.
The Oda field is being developed with a subsea template tied back to the Ula Field Centre via the existing Oselvar infrastructure. Oselvar production was closed down 1 April 2018. The project involves two production wells and one water injector. Aker BP performs the required facilty modifications to receive production from and provide injection water to Oda.
Oda's recoverable reserves are estimated at 48 mmboe (gross). Natural gas from Oda will support Ula development strategy by providing gas for the water alternating gas (WAG) injection regime. Offshore execution of topside and facility modifications on the Ula field center to receive Oda production is ongoing. First oil from Oda is expected in 2019.
On 16 January 2018, the Norwegian Ministry of Petroleum and Energy announced the results of the APA 2017 licensing round. Aker BP was awarded 23 new exploration licenses, of which 14 with the company as operator. These awards support Aker BP's growth strategy by giving access to attractive exploration opportunities both around existing production hubs as well as in new prospective areas.
Drilling of the Frosk prospect in PL340 (Aker BP 65 percent) was completed in February. The well, which is located near Alvheim in the North Sea, proved oil. Preliminary analysis indicate a discovery size of 30-60 million barrels of oil equivalents (mmboe), which is significantly more than the pre-drill estimates of 3 -21 mmboe. The Frosk discovery provides an ideal basis for another profitable expansion project which will secure optimal utilization of the infrastructure in the Alvheim area for many years. The discovery also has a positive impact on the assessment of further exploration potential in the area.
Aker BP completed the drilling of a combined exploration and appraisal well in PL212 (Skarv Unit, Aker BP 23.835 percent) in March. The primary objective was the Kvitungen Tumler prospect, which was dry. The secondary objective of the well was to appraise the Ærfugl field. This was successful, and confirmed the extension of the Ærfugl reservoir. The well fulfills the drilling obligation in PL839 (Aker BP 23.835 percent), as the Kvitungen Tumler prospect extended into this production licence.
Drilling of the Raudåsen prospect in PL790 (Aker BP 30 percent) was also completed in March. The exploration well, located southwest of the Knarr field in the North Sea, was classified as dry with traces of petroleum.
In January, the company entered into an agreement with Fortis Petroleum Norway AS to acquire its working interests in PL869 (20 percent) near the Bøyla field, PL677 (30 percent) near the Vilje field and PL626 (10 percent) near the Hanz field, all in the North Sea.
The transaction has been approved by relevant authorities, and is expected to be completed shortly.
The company continues to build on a strong platform for further value creation through safe operations, an effective business model built on lean principles, technological competence and industrial cooperation to secure long term competitiveness.
Going forward, the company will continue to pursue selective growth opportunities which will enhance production and increase dividend capacity. A quarterly dividend of USD 0.3124 per share is scheduled to be paid in May. Planned total dividend payments in 2018 amount to USD 450 million. The board's intention is to increase the dividend level by USD 100 million each year until 2021.
The company will have five rigs in operation in the second quarter 2018, performing drilling of production and exploration wells as well as maintenance activities and plugging operations. In total, Aker BP plans to participate in a total of 12-14 (8-10 operated) exploration wells in 2018. The exploration plan is subject to continuous optimization.
The company has a robust balance sheet, providing the company with ample financial flexibility going forward.
The company expects 2018 production to be in the range of 155-160 mboepd with a production cost of approximately 12 USD/boe. Capex is expected to be around USD 1.3 billion, exploration spending is estimated to around USD 350 million, and total abandonment expenditures is expected to be around USD 350 million.
Financial statements with notes
| Group | |||||||
|---|---|---|---|---|---|---|---|
| Q1 | 01.01.-31.03. | ||||||
| (USD 1 000) | Note | 2018 | 2017 | 2018 | 2017 | ||
| Petroleum revenues | 891 645 | 647 171 | 891 645 | 647 171 | |||
| Other operating income | -2 045 | -922 | -2 045 | -922 | |||
| Total income | 2 | 889 599 | 646 250 | 889 599 | 646 250 | ||
| Production costs | 173 481 | 120 874 | 173 481 | 120 874 | |||
| Exploration expenses | 3 | 54 661 | 30 259 | 54 661 | 30 259 | ||
| Depreciation | 5 | 185 421 | 184 004 | 185 421 | 184 004 | ||
| Impairments | 4, 5 | - | 29 782 | - | 29 782 | ||
| Other operating expenses | 3 640 | 8 051 | 3 640 | 8 051 | |||
| Total operating expenses | 417 204 | 372 969 | 417 204 | 372 969 | |||
| Operating profit/loss | 472 395 | 273 280 | 472 395 | 273 280 | |||
| Interest income | 4 904 | 1 074 | 4 904 | 1 074 | |||
| Other financial income | 52 544 | 17 272 | 52 544 | 17 272 | |||
| Interest expenses | 32 675 | 30 008 | 32 675 | 30 008 | |||
| Other financial expenses | 71 727 | 34 846 | 71 727 | 34 846 | |||
| Net financial items | 6 | -46 954 | -46 508 | -46 954 | -46 508 | ||
| Profit/loss before taxes | 425 442 | 226 772 | 425 442 | 226 772 | |||
| Taxes (+)/tax income (-) | 7 | 264 197 | 157 955 | 264 197 | 157 955 | ||
| Net profit/loss | 161 245 | 68 818 | 161 245 | 68 818 | |||
| Weighted average no. of shares outstanding basic and diluted | 360 113 509 | 337 737 071 | 360 113 509 | 337 737 071 | |||
| Basic and diluted earnings/loss(-) USD per share | 0.45 | 0.20 | 0.45 | 0.20 |
| Group | |||||
|---|---|---|---|---|---|
| Q1 | 01.01.-31.03. | ||||
| (USD 1 000) | Note | 2018 | 2017 | 2018 | 2017 |
| Profit/loss for the period | 161 245 | 68 818 | 161 245 | 68 818 | |
| Items which may be reclassified over profit and loss (net of taxes) | |||||
| Currency translation adjustment | 73 132 | -356 | 73 132 | -356 | |
| Total comprehensive income in period | 234 376 | 68 461 | 234 376 | 68 461 |
| Group | |||||
|---|---|---|---|---|---|
| (USD 1 000) | Note | 31.03.2018 | 31.03.2017 | 31.12.2017 | |
| ASSETS | |||||
| Intangible assets | |||||
| Goodwill | 5 | 1 860 126 | 1 817 810 | 1 860 126 | |
| Capitalized exploration expenditures | 5 | 391 212 | 355 910 | 365 417 | |
| Other intangible assets | 5 | 1 600 736 | 1 308 011 | 1 617 039 | |
| Tangible fixed assets | |||||
| Property, plant and equipment | 5 | 5 664 761 | 4 599 627 | 5 582 493 | |
| Financial assets | |||||
| Long-term receivables | 42 319 | 43 138 | 40 453 | ||
| Long-term derivatives | 11 | 3 848 | 745 | 12 564 | |
| Other non-current assets | 8 707 | 12 313 | 8 398 | ||
| Total non-current assets | 9 571 710 | 8 137 553 | 9 486 491 | ||
| Inventories | |||||
| Inventories | 80 713 | 68 552 | 75 704 | ||
| Receivables | |||||
| Accounts receivable | 109 471 | 93 142 | 99 752 | ||
| Tax receivables | 7 | 1 666 497 | 394 669 | 1 586 006 | |
| Other short-term receivables | 8 | 511 403 | 459 865 | 535 518 | |
| Short-term derivatives | 11 | 7 241 | 209 | 2 585 | |
| Cash and cash equivalents | |||||
| Cash and cash equivalents | 9 | 37 999 | 182 795 | 232 504 | |
| Total current assets | 2 413 324 | 1 199 232 | 2 532 069 | ||
| TOTAL ASSETS | 11 985 034 | 9 336 785 | 12 018 560 |
| Group | |||||
|---|---|---|---|---|---|
| (USD 1 000) | Note | 31.03.2018 | 31.03.2017 | 31.12.2017 | |
| EQUITY AND LIABILITIES | |||||
| Equity | |||||
| Share capital | 57 056 | 54 349 | 57 056 | ||
| Share premium | 3 637 297 | 3 150 567 | 3 637 297 | ||
| Other equity | -583 879 | -749 748 | -705 756 | ||
| Total equity | 3 110 473 | 2 455 169 | 2 988 596 | ||
| Non-current liabilities | |||||
| Deferred taxes | 7 | 1 357 075 | 1 164 113 | 1 307 148 | |
| Long-term abandonment provision | 15 | 2 814 235 | 2 084 584 | 2 775 622 | |
| Provisions for other liabilities | 10 | 141 228 | 212 862 | 152 418 | |
| Long-term bonds | 13 | 1 127 838 | 512 729 | 622 039 | |
| Long-term derivatives | 11 | - | 27 685 | 13 705 | |
| Other interest-bearing debt | 14 | 459 906 | 1 999 869 | 1 270 556 | |
| Current liabilities | |||||
| Trade creditors | 123 521 | 41 630 | 32 847 | ||
| Accrued public charges and indirect taxes | 17 608 | 19 485 | 27 949 | ||
| Tax payable | 7 | 553 574 | 120 114 | 351 156 | |
| Short-term derivatives | 11 | 10 630 | 1 803 | 7 691 | |
| Short-term abandonment provision | 15 | 194 087 | 96 365 | 268 262 | |
| Short-term interest-bearing debt | 14 | 1 498 159 | - | 1 496 374 | |
| Other current liabilities | 12 | 576 699 | 600 376 | 704 197 | |
| Total liabilities | 8 874 561 | 6 881 616 | 9 029 964 | ||
| TOTAL EQUITY AND LIABILITIES | 11 985 034 | 9 336 785 | 12 018 560 |
| Other equity | ||||||||
|---|---|---|---|---|---|---|---|---|
| Other comprehensive income | ||||||||
| Foreign currency | ||||||||
| Share | Other paid-in | Actuarial | translation | Retained | Total other | |||
| (USD 1 000) | Share capital | premium | capital | gains/(losses) | reserves | earnings | equity | Total equity |
| Equity as of 31.12.2016 | 54 349 | 3 150 567 | 573 083 | -88 | -115 550* | -1 213 154 | -755 709 | 2 449 207 |
| Private placement | 2 706 | 486 729 | - | - | - | - | - | 489 436 |
| Dividend distributed | - | - | - | - | - | -250 000 | -250 000 | -250 000 |
| Profit/loss for the period | - | - | - | - | - | 274 787 | 274 787 | 274 787 |
| Other comprehensive income for the period | - | - | - | -1 | 25 167 | - | 25 166 | 25 166 |
| Equity as of 31.12.2017 | 57 056 | 3 637 297 | 573 083 | -89 | -90 383 | -1 188 366 | -705 756 | 2 988 596 |
| Dividend distributed | - | - | - | - | - | -112 500 | -112 500 | -112 500 |
| Profit/loss for the period | - | - | - | - | - | 161 245 | 161 245 | 161 245 |
| Other comprehensive income for the period | - | - | - | - | 73 132 | - | 73 132 | 73 132 |
| Equity as of 31.03.2018 | 57 056 | 3 637 297 | 573 083 | -89 | -17 251 | -1 139 622 | -583 879 | 3 110 473 |
* The amount arose mainly as a result of the change in functional currency in Q4 2014.
| Group | ||||||
|---|---|---|---|---|---|---|
| Q1 | Year | |||||
| (USD 1 000) | Note | 2018 | 2017 | 2017 | ||
| CASH FLOW FROM OPERATING ACTIVITIES | ||||||
| Profit/loss before taxes | 425 442 | 226 772 | 811 128 | |||
| Taxes paid during the period | -34 381 | - | -101 115 | |||
| Tax refund during the period | - | - | 404 704 | |||
| Depreciation | 5 | 185 421 | 184 004 | 726 670 | ||
| Net impairment losses | 4, 5 | - | 29 782 | 52 349 | ||
| Accretion expenses | 6, 15 | 32 146 | 31 713 | 129 619 | ||
| Interest expenses | 6 | 44 550 | 41 166 | 156 704 | ||
| Interest paid | -51 156 | -41 156 | -145 940 | |||
| Changes in derivatives | 2, 6 | -6 706 | -12 173 | -34 461 | ||
| Amortized loan costs | 6 | 8 124 | 7 144 | 36 900 | ||
| Amortization of fair value of contracts | 10 | 14 195 | - | 11 728 | ||
| Expensed capitalized dry wells | 3, 5 | 13 665 | 1 059 | 75 401 | ||
| Changes in inventories, accounts payable and receivables | 75 947 | -5 718 | -7 583 | |||
| Changes in abandonment liabilities through income statement | - | - | -27 | |||
| Changes in other current balance sheet items | -106 854 | -24 488 | 39 414 | |||
| NET CASH FLOW FROM OPERATING ACTIVITIES | 600 394 | 438 104 | 2 155 491 | |||
| CASH FLOW FROM INVESTMENT ACTIVITIES | ||||||
| Payment for removal and decommissioning of oil fields | 15 | -81 903 | -7 684 | -85 733 | ||
| Disbursements on investments in fixed assets | -256 757 | -232 407 | -977 462 | |||
| Acquisitions of companies (net of cash acquired) | - | - | -2 055 033 | |||
| Cash received from sale of licenses | - | - | 170 959 | |||
| Disbursements on investments in capitalized exploration expenditures and | 5 | -39 460 | -29 905 | -111 724 | ||
| other intangible assets | ||||||
| NET CASH FLOW FROM INVESTMENT ACTIVITIES | -378 119 | -269 996 | -3 058 994 | |||
| CASH FLOW FROM FINANCING ACTIVITIES | ||||||
| Repayment of long-term debt | -815 000 | -35 470 | -777 911 | |||
| Repayment of bond (DETNOR03) | - | - | -330 000 | |||
| Net cash received from issuance of new shares | - | - | 489 436 | |||
| Net proceeds from issuance of debt | 492 423 | - | 1 886 885 | |||
| Paid dividend | -112 500 | -62 500 | -250 000 | |||
| NET CASH FLOW FROM FINANCING ACTIVITIES | -435 077 | -97 970 | 1 018 410 | |||
| Net change in cash and cash equivalents | -212 802 | 70 139 | 114 906 | |||
| Cash and cash equivalents at start of period | 232 504 | 115 286 | 115 286 | |||
| Effect of exchange rate fluctuation on cash held | 18 297 | -2 630 | 2 312 | |||
| CASH AND CASH EQUIVALENTS AT END OF PERIOD | 9 | 37 999 | 182 795 | 232 504 | ||
| SPECIFICATION OF CASH EQUIVALENTS AT END OF PERIOD | ||||||
| Bank deposits and cash | 37 999 | 173 830 | 231 506 | |||
| Restricted bank deposits | - | 8 965 | 998 | |||
| CASH AND CASH EQUIVALENTS AT END OF PERIOD | 9 | 37 999 | 182 795 | 232 504 |
(All figures in USD 1 000 unless otherwise stated)
These interim financial statements have been prepared in accordance with the International Financial Reporting Standards as adopted by the EU ("IFRS") IAS 34 "Interim Financial Reporting", thus the interim financial statements do not include all information required by IFRS and should be read in conjunction with the group's annual financial statement as at 31 December 2017. The interim financial statements reflect all adjustments which are, in the opinion of management, necessary for a fair statement of the financial position, results of operations and cash flows for the dates and interim periods presented. Interim period results are not necessarily indicative of results of operations or cash flows for an annual period. These interim financial statements have not been subject to review or audit by independent auditors.
These interim financial statements were authorised for issue by the Company's Board of Directors on 4 May 2018.
As described in the group's annual financial statements for 2017, two new accounting standards entered into force from 1 January 2018. IFRS 9 Financial Instruments does not have any significant impact on the group's financial statements. IFRS 15 Revenue from contracts with customers has no impact on the line item petroleum revenues in the income statement, but additional details have been provided in the note disclosures (note 2) to specify the part of revenues that arises from change in over/underlift balances.
Except for the changes described above, the accounting princples used for this interim report are consistent with the principles used in the group's annual financial statements as at 31 December 2017.
In preparing these interim financial statements, management has made judgements, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets and liabilities, income and expense. Actual results may differ from these estimates.
The significant judgements made by management in applying the group's accounting policies and the key sources of estimation uncertainty were the same as those that applied to the annual financial statements as at 31 December 2017.
| Group | |||||||
|---|---|---|---|---|---|---|---|
| Q1 | 01.01.-31.03. | ||||||
| Breakdown of petroleum revenues (USD 1 000) | 2018 | 2017 | 2018 | 2017 | |||
| Sales of liquids | 804 701 | 472 575 | 804 701 | 472 575 | |||
| Sales of gas | 139 470 | 94 206 | 139 470 | 94 206 | |||
| Tariff income | 4 979 | 5 654 | 4 979 | 5 654 | |||
| Total petroleum sales | 949 150 | 572 435 | 949 150 | 572 435 | |||
| Impact from change in over/underlift balances of liquids | -57 505 | 74 736 | -57 505 | 74 736 | |||
| Total petroleum revenues | 891 645 | 647 171 | 891 645 | 647 171 |
| Liquids | 11 125 929 | 10 280 386 | 11 125 929 | 10 280 386 |
|---|---|---|---|---|
| Gas | 3 152 497 | 2 800 022 | 3 152 497 | 2 800 022 |
| Total produced volumes | 14 278 426 | 13 080 409 | 14 278 426 | 13 080 409 |
| Other income (USD 1 000) | ||||
| Realized gain/loss (-) on oil derivatives | -3 487 | -2 549 | -3 487 | -2 549 |
| Unrealized gain/loss (-) on oil derivatives | 1 109 | 1 390 | 1 109 | 1 390 |
| Other income | 332 | 237 | 332 | 237 |
| Total other income | -2 045 | -922 | -2 045 | -922 |
| Group | ||||||
|---|---|---|---|---|---|---|
| Q1 | 01.01.-31.03. | |||||
| Breakdown of exploration expenses (USD 1 000) | 2018 | 2017 | 2018 | 2017 | ||
| Seismic | 13 479 | 10 389 | 13 479 | 10 389 | ||
| Area fee | 4 246 | 5 308 | 4 246 | 5 308 | ||
| Field Evaluation | 14 458 | 6 649 | 14 458 | 6 649 | ||
| Dry well expenses | 13 665 | 1 059 | 13 665 | 1 059 | ||
| Other exploration expenses | 8 814 | 6 854 | 8 814 | 6 854 | ||
| Total exploration expenses | 54 661 | 30 259 | 54 661 | 30 259 |
Impairment tests of individual cash-generating units are performed when impairment triggers are identified, and for goodwill impairment is tested at least annually.
As described in previous financial reporting, the technical goodwill recognized in relation to prior year`s business combinations, will be subject to impairment charges as it is fully allocated to the respective individual CGU's. Hence, a quarterly impairment charge is expected if all assumptions remain unchanged. However, in Q1 2018 there has been a positive impact from increase in petroleum prices, together with a headroom from prior periods. Hence, the group's calculation shows that no impairment charge of technical goodwill is needed.
| Assets under | Production facilities |
Fixtures and fittings, office |
||
|---|---|---|---|---|
| (USD 1 000) | development | including wells | machinery | Total |
| Book value 31.12.2016 | 907 108 | 3 501 908 | 32 779 | 4 441 796 |
| Acquisition cost 31.12.2016 | 908 674 | 4 950 566 | 56 137 | 5 915 377 |
| Acquisition of Hess Norge AS | - | 1 076 337 | - | 1 076 337 |
| Additions | 794 809 | -129 338 | 43 401 | 708 873 |
| Disposals | 33 329 | 88 913 | 1 531 | 123 773 |
| Reclassification | -189 466 | 249 149 | 6 339 | 66 021 |
| Acquisition cost 31.12.2017 | 1 480 689 | 6 057 801 | 104 346 | 7 642 835 |
| Accumulated depreciation and impairments 31.12.2016 | 1 566 | 1 448 659 | 23 357 | 1 473 582 |
| Depreciation | - | 622 179 | 13 384 | 635 563 |
| Impairment | -6 | 21 111 | 128 | 21 232 |
| Retirement/transfer depreciations | -1 560 | -66 944 | -1 531 | -70 035 |
| Accumulated depreciation and impairments 31.12.2017 | - | 2 025 004 | 35 338 | 2 060 342 |
| Book value 31.12.2017 | 1 480 689 | 4 032 797 | 69 007 | 5 582 493 |
| Acquisition cost 31.12.2017 | 1 480 689 | 6 057 801 | 104 346 | 7 642 835 |
| Additions | 215 647 | 30 324 | 5 416 | 251 387 |
| Disposals | - | - | - | - |
| Reclassification* | -157 741 | 149 883 | 7 859 | - |
| Acquisition cost 31.03.2018 | 1 538 594 | 6 238 007 | 117 621 | 7 894 222 |
| Accumulated depreciation and impairments 31.12.2017 | - | 2 025 004 | 35 338 | 2 060 342 |
| Depreciation | - | 164 444 | 4 675 | 169 119 |
| Impairment | - | - | - | - |
| Retirement/transfer depreciations | - | - | - | - |
| Accumulated depreciation and impairments 31.03.2018 | - | 2 189 447 | 40 013 | 2 229 461 |
| Book value 31.03.2018 | 1 538 594 | 4 048 560 | 77 607 | 5 664 761 |
* The reclassification is mainly related to infill wells on Boa and Tambar fields
Capitalized exploration expenditures are reclassified to "Fields under development" when the field enters into the development phase. If development plans are subsequently reevaluated, the associated costs remain in assets under development and are not reclassified back to exploration assets. Fields under development are reclassified to "Production facilities" from the start of production. Production facilities, including wells, are depreciated in accordance with the Unit of Production Method. Office machinery, fixtures and fittings etc. are depreciated using the straight-line method over their useful life, i.e. 3 - 5 years. Removal and decommissioning costs are included as production facilities or fields under development.
| Other intangible assets | |||||
|---|---|---|---|---|---|
| (USD 1 000) | Licences etc. | Software | Total | Exploration wells | Goodwill |
| Book value 31.12.2016 | 1 332 534 | 279 | 1 332 813 | 395 260 | 1 846 971 |
| Acquisition cost 31.12.2016 | 1 575 203 | 7 501 | 1 582 705 | 395 260 | 2 720 835 |
| Acquisition of Hess Norge AS | 507 640 | - | 507 640 | - | 181 930 |
| Additions | 156 | - | 156 | 111 569 | |
| Disposals/expensed dry wells | 149 747 | - | 149 747 | 75 401 | 163 791 |
| Reclassification | -11 | - | -11 | -66 011 | - |
| Acquisition cost 31.12.2017 | 1 933 241 | 7 501 | 1 940 742 | 365 417 | 2 738 973 |
| Accumulated depreciation and impairments 31.12.2016 | 242 670 | 7 223 | 249 892 | - | 873 864 |
| Depreciation | 90 863 | 245 | 91 107 | - | - |
| Impairment | 1 956 | - | 1 956 | - | 29 161 |
| Retirement/transfer depreciations | -19 252 | - | -19 252 | - | -24 177 |
| Accumulated depreciation and impairments 31.12.2017 | 316 236 | 7 467 | 323 703 | - | 878 847 |
| Book value 31.12.2017 | 1 617 005 | 34 | 1 617 039 | 365 417 | 1 860 126 |
| Acquisition cost 31.12.2017 | 1 933 241 | 7 501 | 1 940 742 | 365 417 | 2 738 973 |
| Additions | - | - | - | 39 460 | - |
| Disposals/expensed dry wells* | - | - | - | 13 665 | - |
| Reclassification | - | - | - | - | - |
| Acquisition cost 31.03.2018 | 1 933 241 | 7 501 | 1 940 742 | 391 212 | 2 738 973 |
| Accumulated depreciation and impairments 31.12.2017 | 316 236 | 7 467 | 323 703 | - | 878 847 |
| Depreciation | 16 298 | 4 | 16 302 | - | - |
| Impairment | - | - | - | - | - |
| Retirement/transfer depreciations* | - | - | - | - | - |
| Accumulated depreciation and impairments 31.03.2018 | 332 534 | 7 472 | 340 006 | - | 878 847 |
| Book value 31.03.2018 | 1 600 707 | 30 | 1 600 736 | 391 212 | 1 860 126 |
| Group | ||||
|---|---|---|---|---|
| Q1 | 01.01.-31.03. | |||
| Depreciation in the income statement (USD 1 000) | 2018 | 2017 | 2018 | 2017 |
| Depreciation of tangible fixed assets | 169 119 | 159 625 | 169 119 | 159 625 |
| Depreciation of intangible assets | 16 302 | 24 379 | 16 302 | 24 379 |
| Total depreciation in the income statement | 185 421 | 184 004 | 185 421 | 184 004 |
| Impairment in the income statement (USD 1 000) | ||||
| Impairment/reversal of tangible fixed assets | - | -6 | - | -6 |
| Impairment/reversal of intangible assets | - | 627 | - | 627 |
| Impairment of goodwill | - | 29 161 | - | 29 161 |
Total impairment in the income statement - 29 782 - 29 782
| Group | ||||
|---|---|---|---|---|
| Q1 | 01.01.-31.03. | |||
| (USD 1 000) | 2018 | 2017 | 2018 | 2017 |
| Interest income | 4 904 | 1 074 | 4 904 | 1 074 |
| Realized gains on derivatives | 32 295 | 389 | 32 295 | 389 |
| Change in fair value of derivatives | 20 250 | 10 783 | 20 250 | 10 783 |
| Net currency gains | - | 6 100 | - | 6 100 |
| Total other financial income | 52 544 | 17 272 | 52 544 | 17 272 |
| Interest expenses | 44 550 | 41 166 | 44 550 | 41 166 |
| Capitalized interest cost, development projects | -20 000 | -18 301 | -20 000 | -18 301 |
| Amortized loan costs | 8 124 | 7 144 | 8 124 | 7 144 |
| Total interest expenses | 32 675 | 30 008 | 32 675 | 30 008 |
| Net currency losses | 20 792 | - | 20 792 | - |
| Realised loss on derivatives | 4 046 | 1 510 | 4 046 | 1 510 |
| Change in fair value of derivatives | 14 652 | - | 14 652 | - |
| Accretion expenses | 32 146 | 31 713 | 32 146 | 31 713 |
| Other financial expenses | 90 | 1 623 | 90 | 1 623 |
| Total other financial expenses | 71 727 | 34 846 | 71 727 | 34 846 |
| Net financial items | -46 954 | -46 508 | -46 954 | -46 508 |
| Group | ||||
|---|---|---|---|---|
| Q1 | 01.01.-31.03. | |||
| Tax for the period appear as follows (USD 1 000) | 2018 | 2017 | 2018 | 2017 |
| Calculated current year tax | 225 730 | 39 011 | 225 730 | 39 011 |
| Change in deferred tax in the income statement | 59 696 | 120 193 | 59 696 | 120 193 |
| Prior period adjustments | -21 229 | -1 250 | -21 229 | -1 250 |
| Total tax (+)/tax income (-) | 264 197 | 157 955 | 264 197 | 157 955 |
| Group | |||
|---|---|---|---|
| Calculated tax receivable (+)/tax payable (-) (USD 1 000) | 31.03.2018 | 31.03.2017 | 31.12.2017 |
| Tax receivable/payable at 01.01. | 1 234 850 | 307 977 | 307 977 |
| Current year tax (-)/tax receivable (+) | -225 730 | -39 011 | -332 092 |
| Taxes receivable/payable related to acquisitions/sales | - | - | 1 523 512 |
| Net tax payment (+)/tax refund (-) | 34 381 | - | -303 589 |
| Prior period adjustments | 11 458 | 4 216 | 9 502 |
| Currency movements of tax receivable/payable | 57 964 | 1 373 | 29 540 |
| Total net tax receivable (+)/tax payable (-) | 1 112 923 | 274 555 | 1 234 850 |
| Tax receivable included as current assets (+) | 1 666 497 | 394 669 | 1 586 006 |
| Tax payable included as current liabilities (-) | -553 574 | -120 114 | -351 156 |
| Group | |||
|---|---|---|---|
| Deferred tax (-)/deferred tax asset (+) (USD 1 000) | 31.03.2018 | 31.03.2017 | 31.12.2017 |
| Deferred tax/deferred tax asset 01.01. | -1 307 148 | -1 045 542 | -1 045 542 |
| Change in deferred tax in the income statement | -59 696 | -120 193 | -202 715 |
| Deferred tax related to acquisitions/sales | - | - | -61 877 |
| Prior period adjustment | 9 770 | 1 622 | 2 982 |
| Deferred tax charged to OCI and equity | - | - | 5 |
| Net deferred tax (-)/deferred tax asset (+) | -1 357 075 | -1 164 113 | -1 307 148 |
| Group | ||||
|---|---|---|---|---|
| Q1 | 01.01.-31.03. | |||
| Reconciliation of tax expense (USD 1 000) | 2018 | 2017 | 2018 | 2017 |
| 78% tax rate on profit before tax | 331 845 | 176 882 | 331 845 | 176 882 |
| Tax effect of uplift | -31 627 | -30 489 | -31 627 | -30 489 |
| Permanent difference on impairment | - | 22 813 | - | 22 813 |
| Foreign currency translation of NOK monetary items | 16 218 | -3 371 | 16 218 | -3 371 |
| Foreign currency translation of USD monetary items | 110 572 | 12 001 | 110 572 | 12 001 |
| Tax effect of financial and other 23%/24% items | -61 469 | -3 917 | -61 469 | -3 917 |
| Currency movements of tax balances* | -84 993 | -12 177 | -84 993 | -12 177 |
| Other permanent differences and prior period adjustment | -16 347 | -3 788 | -16 347 | -3 788 |
| Total taxes (+)/tax income (-) | 264 197 | 157 955 | 264 197 | 157 955 |
* Tax balances are in NOK and converted to USD using the period end currency rate. When NOK weakens against USD, the tax rate increases as there is less remaining tax depreciation measured in USD (vice versa).
The tax rate for general corporation tax changed from 24 to 23 per cent from 1 January 2018. The rate for special tax changed from from the same date from 54 to 55 per cent.
In accordance with statutory requirements, the calculation of current tax is required to be based on NOK functional currency. This may impact the tax rate as the company's functional currency is USD.
| Group | ||||
|---|---|---|---|---|
| (USD 1 000) | 31.03.2018 | 31.03.2017 | 31.12.2017 | |
| Prepayments | 47 597 | 28 922 | 59 100 | |
| VAT receivable | 14 863 | 7 262 | 10 856 | |
| Underlift of petroleum | 78 016 | 65 245 | 118 012 | |
| Accrued income from sale of petroleum products | 247 637 | 132 165 | 105 670 | |
| Other receivables, mainly from licenses | 123 290 | 226 272 | 241 879 | |
| Total other short-term receivables | 511 403 | 459 865 | 535 518 |
The item 'Cash and cash equivalents' consists of bank accounts and short-term investments that constitute parts of the group's transaction liquidity.
| Group | ||||
|---|---|---|---|---|
| Breakdown of cash and cash equivalents (USD 1 000) | 31.03.2018 | 31.03.2017 | 31.12.2017 | |
| Bank deposits | 37 999 | 173 830 | 231 506 | |
| Restricted funds (tax withholdings)* | - | 8 965 | 998 | |
| Cash and cash equivalents | 37 999 | 182 795 | 232 504 | |
| Unused revolving credit facility | - | 550 000 | - | |
| Unused reserve-based lending facility (see note 14) | 3 485 000 | 1 866 000 | 2 670 000 |
* During Q4 2017, the company extended its bank guarantee related to withheld payroll tax to NOK 300 million. In Q1 2018 the remaining restricted funds were released in full.
| Group | |||
|---|---|---|---|
| Breakdown of provisions for other liabilities (USD 1 000) | 31.03.2018 | 31.03.2017 | 31.12.2017 |
| Fair value of contracts assumed in acquisitions* | 138 282 | 191 406 | 149 031 |
| Other long term liabilities | 2 947 | 21 456 | 3 387 |
| Total provisions for other liabilities | 141 228 | 212 862 | 152 418 |
* The negative contract values are related to rig contracts entered into by the acquirees, which were different from current market terms at the time of the acquisitions. The fair value is based on the difference between market price and contract price at the time of the acquisitions. The balance is split between current and non-current liabilities based on the cash flow in the contracts, and amortized over the lifetime of the contracts.
| Group | |||
|---|---|---|---|
| (USD 1 000) | 31.03.2018 | 31.03.2017 | 31.12.2017 |
| Unrealized gain interest rate swaps | 1 613 | - | - |
| Unrealized gain currency contracts | 2 236 | 745 | 12 564 |
| Long-term derivatives included in assets | 3 848 | 745 | 12 564 |
| Unrealized gain on commodity derivatives | - | 209 | - |
| Unrealized gain currency contracts | 7 241 | - | 2 585 |
| Short-term derivatives included in assets | 7 241 | 209 | 2 585 |
| Total derivatives included in assets | 11 090 | 954 | 15 149 |
| Unrealized losses currency contracts | - | 393 | - |
| Unrealized losses interest rate swaps | - | 27 292 | 13 705 |
| Long-term derivatives included in liabilities | - | 27 685 | 13 705 |
| Unrealized losses currency contracts | 4 048 | 1 803 | - |
| Unrealized losses commodity derivatives | 6 582 | - | 7 691 |
| Short-term derivatives included in liabilities | 10 630 | 1 803 | 7 691 |
| Total derivatives included in liabilities | 10 630 | 29 489 | 21 396 |
The group has different types of hedging instruments. The commodity derivatives are used to hedge the risk of oil price reduction. The group manages its interest rate exposure using interest rate derivatives, including a cross currency interest rate swap. Foreign currency exchange derivatives are used to manage the company's exposure to currency risks, mainly NOK, EUR and GBP. These derivatives are mark to market with changes in market value recognized in the income statement.The nature of the instruments and the valuation method is consistent with the disclosed information in the annual financial statements as at 31 December 2017.
| Group | |||
|---|---|---|---|
| Breakdown of other current liabilities (USD 1 000) | 31.03.2018 | 31.03.2017 | 31.12.2017 |
| Current liabilities against JV partners | 77 484 | 97 487 | 81 223 |
| Share of other current liabilities in licences | 277 739 | 355 043 | 409 387 |
| Overlift of petroleum | 24 368 | 2 275 | 9 610 |
| Fair value of contracts assumed in acquisitions* | 57 322 | 45 939 | 62 097 |
| Other current liabilities** | 139 786 | 99 631 | 141 880 |
| Total other current liabilities | 576 699 | 600 376 | 704 197 |
* Refer to note 10.
** Other current liabilities include unpaid wages and vacation pay, accrued interest and other provisions.
| Group | |||
|---|---|---|---|
| (USD 1 000) | 31.03.2018 | 31.03.2017 | 31.12.2017 |
| DETNOR02 Senior unsecured bond 1) | 243 316 | 216 909 | 230 375 |
| DETNOR03 Subordinated PIK toggle bond 2) | - | 295 820 | - |
| AKERBP – Senior Notes (17/22) 3) | 392 099 | - | 391 664 |
| AKERBP – Senior Notes (18/25) 4) | 492 423 | - | - |
| Long-term bonds | 1 127 838 | 512 729 | 622 039 |
1) The loan is denominated in NOK and runs from July 2013 to July 2020 and carries an interest rate of 3 month NIBOR + 6.5 per cent. The principal falls due on July 2020 and interest is paid on a quarterly basis. The loan is unsecured. The loan has been swapped into USD using a cross currency interest rate swap whereby the group pays LIBOR + 6.81 per cent quarterly. The financial covenants for this bond are consistent with the RBL as described in note 14.
2) As described in the Q2 2017 report, the bond was repaid in July 2017.
3) The bond was established in July 2017 and carries an interest of 6 per cent. The principal falls due in July 2022 and interest is paid on a semi annual basis. The loan is senior unsecured and has no financial covenants.
4) The bond was established in March 2018 and carries an interest of 5.875 per cent. The principal falls due in March 2025 and interest is paid on a semi annual basis. The loan is senior unsecured and has no financial covenants.
| Group | |||
|---|---|---|---|
| (USD 1 000) | 31.03.2018 | 31.03.2017 | 31.12.2017 |
| Reserve-based lending facility | 459 906 | 1 999 869 | 1 270 556 |
| Long-term interest-bearing debt | 459 906 | 1 999 869 | 1 270 556 |
| Bridge facility | 1 498 159 | - | 1 496 374 |
| Short-term interest-bearing debt | 1 498 159 | - | 1 496 374 |
The RBL facility was established in 2014 and is a senior secured seven-year facility. The facility was originally USD 3.0 billion, with an additional uncommitted accordion option of USD 1.0 billion. In connection with the acquisition of BP Norge AS, the facility size was increased to USD 4.0 billion. In addition a new, uncommitted, accordion option of USD 1.0 billion was added to the facility.
Current availability under the RBL is USD 4 billion. The financial covenants are as follows:
Leverage Ratio shall be maximum 4 untill the production start of Johan Sverdrup, thereafter maximum 3.5
Interest Coverage Ratio shall be minimum 3.5
The interest rate is from 1 - 6 months LIBOR plus a margin of 2 - 3 per cent based on drawn amount. In addition, a commitment fee is paid on unused credit.
In relation to the acquisition of Hess Norge AS, the company obtained a new USD 1.5 billion bank facility ("Bridge facility"). The facility has a duration of 18 months, carries an interest of Libor + 1.5 per cent (the margin increases to 2.0 per cent after nine months), and is secured by a pledge in the shares of Aker BP AS (previously Hess Norge AS). The company expects the tax losses from Aker BP AS to be settled during 2018. Such settlement would trigger a mandatory repayment of the USD 1.5 billion bank facility. The financial covenants in this facility are consistent with the RBL.
| Group | |||||
|---|---|---|---|---|---|
| (USD 1 000) | 31.03.2018 | 31.03.2017 | 31.12.2017 | ||
| Provisions as of 1 January | 3 043 884 | 2 156 921 | 2 156 921 | ||
| Abondonment liability from acquisitions | - | - | 1 315 181 | ||
| Change in abandonment liability due to asset sales | - | - | -207 516 | ||
| Incurred cost removal | -67 707 | -7 684 | -74 005 | ||
| Accretion expense - present value calculation | 32 146 | 31 713 | 129 619 | ||
| Change in estimates and incurred liabilities on new drilling and installations | - | - | -276 315 | ||
| Total provision for abandonment liabilities | 3 008 323 | 2 180 950 | 3 043 884 | ||
| Break down of the provision to short-term and long-term liabilities | |||||
| Short-term | 194 087 | 96 365 | 268 262 | ||
| Long-term | 2 814 235 | 2 084 584 | 2 775 622 | ||
| Total provision for abandonment liabilities | 3 008 323 | 2 180 950 | 3 043 884 |
The estimate is based on executing a concept for abandonment in accordance with the Petroleum Activities Act and international regulations and guidelines. The calculations assume an inflation rate of 2.5 per cent and a nominal discount rate before tax of between 3.44 per cent and 4.42 per cent.
During the normal course of its business, the group will be involved in disputes, including tax disputes. The group has made accruals for probable liabilities related to litigation and claims based on management's best judgment and in line with IAS 37 and IAS 12.
The company has not identified any events with significant accounting impacts that have occured between the end of the reporting period and the date of this report.
| Fields operated: | 31.03.2018 | 31.12.2017 |
|---|---|---|
| Alvheim | 65.000% | 65.000 % |
| Bøyla | 65.000% | 65.000 % |
| Hod | 90.000% | 90.000 % |
| Ivar Aasen Unit | 34.786% | 34.786 % |
| Jette Unit | 70.000% | 70.000 % |
| Valhall | 90.000% | 90.000 % |
| Vilje | 46.904% | 46.904 % |
| Volund | 65.000% | 65.000 % |
| Tambar | 55.000% | 55.000 % |
| Tambar Øst | 46.200% | 46.200 % |
| Ula | 80.000% | 80.000 % |
| Skarv | 23.835% | 23.835 % |
Production licences in which Aker BP is the operator:
| Licence: | 31.03.2018 | 31.12.2017 Licence: | 31.03.2018 | 31.12.2017 |
|---|---|---|---|---|
| PL 001B | 35.000% | 35.000 % PL 777 | 40.000% | 40.000 % |
| PL 006B | 90.000% | 90.000 % PL 777B | 40.000% | 40.000 % |
| PL 019 | 80.000% | 80.000 % PL 777C | 40.000% | 40.000 % |
| PL 019C | 80.000% | 80.000 % PL 777D** | 40.000% | 0.000 % |
| PL 019E** | 80.000% | 0.000 % PL 784 | 40.000% | 40.000 % |
| PL 026B | 90.260% | 90.260 % PL 790 | 30.000% | 30.000 % |
| PL 027D | 100.000% | 100.000 % PL 814 | 40.000% | 40.000 % |
| PL 028B | 35.000% | 35.000 % PL 818 | 40.000% | 40.000 % |
| PL 033 | 90.000% | 90.000 % PL 818B** | 40.000% | 0.000 % |
| PL 033B | 90.000% | 90.000 % PL 821* | 0.000% | 60.000 % |
| PL 036C | 65.000% | 65.000 % PL 821B* | 0.000% | 60.000 % |
| PL 036D | 46.904% | 46.904 % PL 822S | 60.000% | 60.000 % |
| PL 065 | 55.000% | 55.000 % PL 839 | 23.835% | 23.835 % |
| PL 065B** | 55.000% | 0.000 % PL 843 | 40.000% | 40.000 % |
| PL 088BS | 65.000% | 65.000 % PL 858 | 40.000% | 40.000 % |
| PL 150 | 65.000% | 65.000 % PL 861 | 50.000% | 50.000 % |
| PL 150B* | 0.000% | 65.000 % PL 867 | 40.000% | 40.000 % |
| PL 169C | 50.000% | 50.000 % PL 868 | 60.000% | 60.000 % |
| PL 203 | 65.000% | 65.000 % PL 869 | 40.000% | 40.000 % |
| PL 203B | 65.000% | 65.000 % PL 872 | 40.000% | 40.000 % |
| PL 212 | 30.000% | 30.000 % PL 873 | 40.000% | 40.000 % |
| PL 212B | 30.000% | 30.000 % PL 874 | 90.260% | 90.260 % |
| PL 212E | 30.000% | 30.000 % PL 893 | 60.000% | 60.000 % |
| PL 242 | 35.000% | 35.000 % PL 895 | 60.000% | 60.000 % |
| PL 261 | 50.000% | 50.000 % PL 906** | 40.000% | 0.000 % |
| PL 262 | 30.000% | 30.000 % PL 907** | 40.000% | 0.000 % |
| PL 300 | 55.000% | 55.000 % PL 914S** | 34.786% | 0.000 % |
| PL 340 | 65.000% | 65.000 % PL 915** | 35.000% | 0.000 % |
| PL 340BS | 65.000% | 65.000 % PL 916** | 40.000% | 0.000 % |
| PL 364 | 90.260% | 90.260 % PL 919** | 65.000% | 0.000 % |
| PL 442 | 90.260% | 90.260 % PL 932** | 60.000% | 0.000 % |
| PL 442B | 90.260% | 90.260 % PL 941** | 50.000% | 0.000 % |
| PL 460 | 65.000% | 65.000 % PL 948** | 40.000% | 0.000 % |
| PL 504 | 47.593% | 47.593 % PL 951** | 40.000% | 0.000 % |
| PL 626 | 50.000% | 50.000 % | ||
| PL 659 | 50.000% | 50.000 % | ||
| PL 677 | 60.000% | 60.000 % | ||
| PL 724* | 0.000% | 40.000 % | ||
| PL 724B* | 0.000% | 40.000 % | ||
| PL 748 | 50.000% | 50.000 % | ||
| PL 748B | 50.000% | 50.000 % | ||
| PL 762 | 20.000% | 20.000 % | ||
| Number of licenses in which Aker BP is the operator | 71 | 62 |
* Relinquished licenses or Aker BP has withdrawn from the license.
** Interest awarded in the APA Licensing round (Application in Predefined Areas) in 2017. The awards were announced in 2018.
| Fields non-operated: | 31.03.2018 | 31.12.2017 |
|---|---|---|
| Atla | 10.000% | 10.000 % |
| Enoch | 2.000% | 2.000 % |
| Gina Krog | 3.300% | 3.300 % |
| Johan Sverdrup | 11.573% | 11.5733 % |
| Oda | 15.000% | 15.000 % |
| Varg | 5.000% | 5.000 % |
Production licences in which Aker BP is a partner:
| Licence: | 31.03.2018 | 31.12.2017 |
|---|---|---|
| PL 006C | 15.000% | 15.000 % |
| PL 006E** | 15.000% | 0.000 % |
| PL 018DS | 13.338% | 13.338 % |
| PL 026 | 30.000% | 30.000 % |
| PL 029B | 20.000% | 20.000 % |
| PL 035 | 50.000% | 50.000 % |
| PL 035C | 50.000% | 50.000 % |
| PL 038 | 5.000% | 5.000 % |
| PL 048D | 10.000% | 10.000 % |
| PL 102C | 10.000% | 10.000 % |
| PL 102D | 10.000% | 10.000 % |
| PL 102F | 10.000% | 10.000 % |
| PL 102G | 10.000% | 10.000 % |
| PL 220 | 15.000% | 15.000 % |
| PL 265 | 20.000% | 20.000 % |
| PL 272 | 50.000% | 50.000 % |
| PL 405 | 15.000% | 15.000 % |
| PL 457BS | 40.000% | 40.000 % |
| PL 492 | 60.000% | 60.000 % |
| PL 502 | 22.222% | 22.222 % |
| PL 533 | 35.000% | 35.000 % |
| PL 533B** | 35.000% | 0.000 % |
| PL 554 | 30.000% | 30.000 % |
| PL 554B | 30.000% | 30.000 % |
| PL 554C | 30.000% | 30.000 % |
| PL 554D** | 30.000% | 0.000 % |
| PL 627* | 0.000% | 20.000 % |
| PL 627B* | 0.000% | 20.000 % |
| PL 719 | 20.000% | 20.000 % |
| PL 721 | 40.000% | 40.000 % |
| PL 722 | 20.000% | 20.000 % |
| PL 782S | 20.000% | 20.000 % |
| PL 782SB | 20.000% | 20.000 % |
| PL 782SC | 20.000% | 20.000 % |
| PL 810 | 30.000% | 30.000 % |
| PL 810B** | 30.000% | 0.000 % |
| PL 811 | 20.000% | 20.000 % |
| PL 813 | 3.300% | 3.300 % |
| PL 838 | 30.000% | 30.000 % |
| PL 842 | 30.000% | 30.000 % |
| PL 844 | 20.000% | 20.000 % |
| PL 852 | 40.000% | 40.000 % |
| PL 852B** | 40.000% | 0.000 % |
| PL 857 | 20.000% | 20.000 % |
| PL 862 | 50.000% | 50.000 % |
| PL 863 | 40.000% | 40.000 % |
| PL 863B** | 40.000% | 0.000 % |
| PL 864 | 20.000% | 20.000 % |
| PL 871 | 20.000% | 20.000 % |
| PL 891 | 30.000% | 30.000 % |
| PL 892 | 30.000% | 30.000 % |
| PL 902 | 30.000% | 30.000 % |
| PL 942** | 30.000% | 0.000 % |
| PL 954** | 20.000% | 0.000 % |
| PL 955** | 30.000% | 0.000 % |
| Number of licenses in which Aker BP is a partner | 53 | 46 |
* Relinquished licenses or Aker BP has withdrawn from the license.
** Interest awarded in the APA Licensing round (Application in Predefined Areas) in 2017. The awards were announced in 2018.
| 2018 2017 |
2016 | |||||||
|---|---|---|---|---|---|---|---|---|
| (USD 1 000) | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 |
| Total income | 889 599 | 725 994 | 596 188 | 594 501 | 646 250 | 655 624 | 247 993 | 255 665 |
| Production costs | 173 481 | 147 076 | 134 411 | 121 017 | 120 874 | 121 139 | 32 188 | 39 116 |
| Exploration expenses | 54 661 | 56 181 | 63 887 | 75 375 | 30 259 | 44 281 | 30 843 | 36 214 |
| Depreciation | 185 421 | 183 138 | 175 334 | 184 194 | 184 004 | 159 796 | 114 649 | 120 264 |
| Impairments | - | 21 111 | 1 091 | 365 | 29 782 | 44 627 | 8 429 | -19 644 |
| Other operating expenses | 3 640 | 13 549 | 2 893 | 3 113 | 8 051 | 5 029 | 6 223 | 5 410 |
| Total operating expenses | 417 204 | 421 055 | 377 617 | 384 065 | 372 969 | 374 872 | 192 333 | 181 360 |
| Operating profit/loss | 472 395 | 304 940 | 218 571 | 210 436 | 273 280 | 280 752 | 55 660 | 74 305 |
| Net financial items | -46 954 | -56 526 | -9 469 | -83 597 | -46 508 | -70 572 | -5 107 | -28 951 |
| Profit/loss before taxes | 425 442 | 248 413 | 209 102 | 126 840 | 226 772 | 210 180 | 50 553 | 45 353 |
| Taxes (+)/tax income (-) | 264 197 | 214 377 | 97 065 | 66 944 | 157 955 | 277 183 | -12 880 | 39 046 |
| Net profit/loss | 161 245 | 34 036 | 112 037 | 59 896 | 68 818 | -67 003 | 63 433 | 6 308 |
Aker BP may disclose alternative performance measures as part of its financial reporting as a supplement to the financial statements prepared in accordance with IFRS. Aker BP believes that the alternative performance measures provide useful supplemental information to management, investors, security analysts and other stakeholders and are meant to provide an enhanced insight into the financial development of Aker BP's business operations and to improve comparability between periods.
Depreciation per boe is depreciation divided by number of barrels of oil equivalents produced in the corresponding period
Dividend per share (DPS) is dividend paid in the quarter divided by number of shares outstanding
EBIT is short for earnings before interest and other financial items and taxes
EBITDA is short for earnings before interest and other financial items, taxes, depreciation and amortisation and impairments
EBITDAX is short for earnings before interest and other financial items, taxes, depreciation and amortisation, impairments and exploration expenses
Equity ratio is total equity divided by total assets
Net interest-bearing debt is book value of current and non-current interest-bearing debt less cash and cash equivalents
Production cost per boe is production cost divided by number of barrels of oil equivalents produced in the corresponding period
Fornebuporten, Building B Oksenøyveien 10 1366 Lysaker
Post: Postboks 65, 1324 Lysaker
Telefon: +47 51 35 30 00 E-post: [email protected]
www.akerbp.com
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