Quarterly Report • Feb 6, 2017
Quarterly Report
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QUARTERLY REPORT FOR AKER BP ASA
FORNEBU, 6 FEBRUARY 2017
| 3 October: | The company announced the acquisition of licenses from Tullow Norge AS, including 15 percent interest in the Oda discovery |
|---|---|
| 14 October: | The bondholder meeting in the DETNOR02 bond resolved certain amendments, including to remove restrictions related to dividend disbursements from the loan agreement |
| 10 November: | The company announced start-up of production from Viper- Kobra, which is tied back to the Alvheim FPSO |
| 24 November: | The Extraordinary General Meeting approved a dividend payment of USD 125 million for disbursement in December 2016 and March 2017 |
| 30 November: | The Plan for Development of Oda (15 percent working interest) was submitted to the Ministry of Petroleum and Energy (MPE) |
| 24 December: | The company announced production start-up at the Ivar Aasen field |
| KEY EVENTS AFTER THE QUARTER | |
| 16 January: | The company announced year-end 2016 preliminary P50 reserves of 711 million barrels of oil equivalents ("mmboe") and mean contingent resources of 600 mmboe |
| 17 January: | The company was offered ownership in 21 new licenses, including 13 operatorship in the 2016 Awards in Pre-defined |
Areas ("APA")
| Unit | Q4 2016 | Q4 2015 | 2016 | 2015 | |
|---|---|---|---|---|---|
| Operating income | USDm | 656 | 255 | 1 364 | 1 222 |
| EBITDA | USDm | 485 | 208 | 968 | 953 |
| Net result | USDm | -67 | -156 | 35 | -313 |
| Earnings per share (EPS) | USD | -0.20 | -0.77 | 0.15 | -1.54 |
| Production cost per barrel | USD/boe | 10 | 5 | 8 | 6 |
| Depreciation per barrel | USD/boe | 14 | 22 | 18 | 22 |
| Cash flow from operations | USDm | 320 | 122 | 896 | 686 |
| Cash flow from investments | USDm | -313 | -439 | -705 | -1 168 |
| Total assets | USDm | 9 255 | 5 189 | 9 255 | 5 189 |
| Net interest-bearing debt | USDm | 2 425 | 2 532 | 2 425 | 2 532 |
| Cash and cash equivalents | USDm | 115 | 91 | 115 | 91 |
| Unit | Q4 2016 | Q4 2015 | 2016 | 2015 | |
|---|---|---|---|---|---|
| Alvheim (65%) | boepd | 53 683 | 30 865 | 43 290 | 34 133 |
| Bøyla (65%) | boepd | 6 470 | 8 838 | 7 411 | 9 006 |
| Hod (37.5%) | boepd | 596 | - | 150 | - |
| Ivar Aasen (34.8%) | boepd | 838 | - | 211 | - |
| Skarv (23.8%) | boepd | 30 040 | - | 7 551 | - |
| Tambar / Tambar East (55.0%/46.2%) | boepd | 2 070 | - | 520 | - |
| Ula (80%) | boepd | 5 057 | - | 1 271 | - |
| Valhall (36.0%) | boepd | 17 505 | - | 4 400 | - |
| Vilje (46.9%) | boepd | 6 221 | 5 741 | 6 599 | 6 376 |
| Volund (65%) | boepd | 3 462 | 7 326 | 5 027 | 9 040 |
| Other (Jette, Jotun, Varg, Atla, Enoch) | boepd | 578 | 1 226 | 1 010 | 1 449 |
| SUM | boepd | 126 520 | 53 996 | 77 441 | 60 004 |
| Oil price | USD/bbl | 52 | 45 | 47 | 54 |
| Gas price | USD/scm | 0.19 | 0.23 | 0.18 | 0.27 |
3
Aker BP ASA ("the company" or "Aker BP") reported total income of USD 656 (255) million in the fourth quarter of 2016. Production in the period was 126.5 (54.0) thousand barrels of oil equivalent per day ("mboepd"), realizing an average oil price of USD 52 (45) per barrel and a gas price of USD 0.19 (0.23) per standard cubic metre (scm).
EBITDA amounted to USD 485 (208) million in the quarter and EBIT was USD 281 (-95) million. Net loss for the quarter was USD 67 (156) million, translating into an EPS of USD -0.20 (-0.77). Net interest-bearing debt amounted to USD 2,425 (2,532) million per December 31, 2016.
After the merger, the integration between Det norske oljeselskap ASA ("Det norske") and BP Norge AS was completed on December 1, 2016, marking "day one" for the new organisation. All licences and activity of BP Norge AS have been transferred to Aker BP.
The Valhall area passed 1 billion boe produced late 2016 and preparations are ongoing to resume drilling on the field from the injection platform in early 2017. Production from the Skarv area was high and stable in the quarter. Ula production was impacted by shut-ins and well conversion.
Production from the Alvheim area has been stable and high in the fourth quarter, positively impacted by the start-up of Viper-Kobra in November. The Transocean Arctic drilling rig commenced infill drilling at Volund in December.
A major milestone was achieved with the production start-up of Ivar Aasen in December – on schedule and within the overall budget framework. The Johan Sverdrup project is progressing according to plan and the pre-drilling campaign was completed during the quarter. The development plan for the Oda development was submitted to the authorities in November.
In December, the company paid its first dividend of USD 0.185 per share.
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, and is for 2015 not directly comparable as they represent Aker BP ASA prior to the merger with BP Norge AS.
| (USD million) | Q4 2016 | Q4 2015 |
|---|---|---|
| Operating income | 656 | 255 |
| EBITDA | 485 | 208 |
| EBIT | 281 | -95 |
| Pre-tax profit/loss | 210 | -151 |
| Net profit | -67 | -156 |
| EPS (USD) | -0.20 | -0.77 |
| (USD million) | Q4 2016 | Q4 2015 |
|---|---|---|
| Goodwill | 1 847 | 768 |
| PP&E | 4 442 | 2 979 |
| Cash & cash equivalents | 115 | 91 |
| Total assets | 9 255 | 5 189 |
| Equity | 2 449 | 339 |
| Interest-bearing debt | 2 541 | 2 622 |
Total income in the fourth quarter was USD 656 (255) million, higher than the fourth quarter 2015 mainly due to inclusion of BP Norge AS activities. Petroleum revenues accounted for USD 542 (218) million, while other income was USD 114 (36) million, primarily relating to gains on a change in pension scheme following the merger with BP Norge.
Exploration expenses amounted to USD 44 (19) million in the quarter, reflecting dry hole costs, seismic costs, area fees and G&G activities. Production costs were USD 121 (24) million, equating to 10.4 (4.8) USD/boe, including transportation cost of 2.8 USD/boe. The increase from the fourth quarter 2015 was mainly due to inclusion of BP Norge fields with a higher production cost per boe compared to the Alvheim area. Other operating expenses amounted to USD 5 (3) million, a slight increase from the fourth quarter 2015.
Depreciation amounted to USD 160 (112) million, corresponding to 14 (22) USD/boe, which represents a decrease from fourth quarter 2015 mainly due to the inclusion of the BP Norge assets. During the quarter, an impairment of USD 45 (192) million mainly related to technical goodwill from the merger with BP Norge, was recognized.
The company recorded an operating profit of USD 281 (-95) million in the fourth quarter, higher than the fourth quarter 2015 primarily due to the merger with BP Norge, higher oil prices and the curtailment gain on pensions. The net loss for the period was USD 67 (156) million after net financial items of USD 71 (56) million and a tax expense of USD 277 (5) million. The tax expense is primarily related to a change in deferred taxes, significantly impacted by a weaker NOK against the USD in the quarter as well as the tax effect of the above mentioned curtailment gain on pensions Earnings per share were USD -0.20 (-0.77).
Total intangible assets amounted to USD 3,575 (1,706) million, of which goodwill was USD 1,847 (768) million. The increase from the fourth quarter 2015 is related to the merger with BP Norge AS.
Property, plant and equipment increased to USD 4,442 (2,979) million, reflecting the increase related to the acquisition of BP Norge AS and investments in development projects, less depreciation. Current tax receivables amounted to USD 401 (126) million at the end of the quarter relating to exploration spend and anticipated payout of tax losses from BP Norge.
The group's cash and cash equivalents were USD 115 (91) million as of 31 December. Total assets were USD 9,255 (5,189) million at the end of the quarter.
Equity amounted to USD 2,449 (339) million at the end of the quarter, corresponding to an equity ratio of 26 (7) percent. The increase is mainly related to the share issue in connection with the merger with BP Norge AS in the third quarter 2016.
Deferred tax liabilities decreased to USD 1,046 (1,356) million and are detailed in note 7 to the financial statements.
Gross interest-bearing debt decreased to USD 2,541 (2,622) million, consisting of the DETNOR02 bond of USD 215 million, the DETNOR03 bond of USD 296 million and the Reserve Based Lending ("RBL") facility of USD 2,030 million.
| (USD million) | Q4 2016 | Q4 2015 |
|---|---|---|
| Cash flow from operations | 320 | 122 |
| Cash flow from investments | -313 | -439 |
| Cash flow from financing | -675 | 204 |
| Net change in cash & cash eq. | -668 | -113 |
| Cash and cash eq. EOQ | 115 | 91 |
Net cash flow from operating activities was USD 320 (122) million, including a tax refund of USD 129 million, relating to 2015 exploration activity and tax adjustments related to previous periods.
Net cash flow from investment activities was USD -313 (-439) million. Investments in fixed assets amounted to USD 244 (229) million for the quarter, mainly reflecting CAPEX on Ivar Aasen, Alvheim and Johan Sverdrup. Investments in intangible assets including capitalized exploration were USD 62 (81) million in the quarter.
Net cash flow from financing activities totaled USD -675 (204) million, reflecting the net amount repaid on the group's RBL facility and dividend disbursements of USD 62.5 million during the quarter.
Following the announcement of the merger with BP Norge, the company made certain changes to its two bank facilities, including an increase in its reserve-based lending ("RBL") facility from USD 3.0 to 4.0 billion and certain amendments to the loan documentation. In addition, the RBL facility includes an uncommitted accordion option of USD 1.0 billion.
Amendments to the bank loan agreements include removal of the dividend restriction, replaced by a leverage ratio incurrence test of 4.5x (Net interest-bearing debt / EBITDAX). The updated security package was finalized in December 2016 and the new borrowing base was set at USD 3.9 billion until the end of June 2017.
In October, the bondholder meeting in the DETNOR02 bond loan approved a proposal to remove restrictions related to dividend disbursements and replaced that clause with an incurrence test aligned with the banks, and a put option. As compensation, the DETNOR02 bonds will be repaid at 107 percent of par (+3 percent compared to the previous repayment level) at maturity in 2020.
Bondholders representing NOK 3.5 million nominal worth of DETNOR02 bonds exercised the distribution put option following the dividend payment in December. Aker BP consequently owns bonds equal to NOK 3.5 million.
In view of the merger with BP Norge AS, the company is evaluating its capital structure and debt composition going forward.
The company seeks to reduce the risk related to foreign exchange rates, interest rates and commodity prices through hedging instruments.
During the fourth quarter, the company benefitted from the realisation of the last of the 55 USD/bbl put options entered into during the first half of 2015. During the fourth quarter 2016, the company entered into new commodity hedges for 2017. These include put options with a strike price of 50 USD/bbl for approximately 15 percent of estimated 2017 oil production, corresponding to approximately 50 percent of the undiscounted aftertax value.
The company actively manages its foreign currency exposure through a mix of forward contracts and options.
In November, the Extraordinary General Meeting approved the Board of Directors proposal to pay a dividend of USD 125 million, split equally for Q4 2016 and Q1 2017. This translates into a dividend per share (DPS) of USD 0.185 per quarter. The first dividend of USD 0.185 per share was disbursed on December 7, 2016 and the next dividend payment is expected to be disbursed on or about February 17, 2017.
Dividends post March 2017 will be proposed to the Annual General Meeting in April 2017. The company aims to sustain a minimum dividend level of USD 250 million per year going forward, payable quarterly and to increase this level once Johan Sverdrup is in production.
HSE is always the number one priority in all Aker BP's activities. The company ensures that all its operations and projects are carried out under the highest HSE standards.
During fourth quarter, one high potential incident (HIPO) was recorded, which was a dropped object on the Maersk Interceptor. The incident has been thoroughly investigated and learnings distributed and implemented.
There has been one restricted work incident and seven medical treatment cases. In connection to Ivar Aasen hook up there have been minor incidents, all of which have been addressed in safety stand downs and close follow-up by leadership in the project. The hook-up and start-up phase have been conducted without any major incidents or accidents.
A new enterprise risk management process for the company has been defined and the company risk matrix has been developed based on risk matrices at business unit level. This risk process will be rolled out in the whole organization during the next quarter.
The Petroleum Safety Authority conducted the last supervisory audit on the integration process in the fourth quarter and there were no deviations recorded.
The company has also reorganized its emergency preparedness organization of the onshore response teams in order to make it more robust and effective.
Aker BP produced 11.6 (5.0) mmboe in the fourth quarter of 2016, corresponding to 126.5 (54.0) mboepd. The average realized oil price was USD 52 (45) per barrel, while gas revenues were recognized at market value of USD 0.19 (0.22) per standard cubic metre (scm).
The producing fields Alvheim (including Viper-Kobra, 65 percent), Volund (65 percent), Bøyla (65 percent) and Vilje (46.9 percent) are all tied back to the Alvheim FPSO.
Production from the Alvheim area has been stable and high in the fourth quarter, with a total production efficiency of 96.6 percent.
In November, the production from the Viper-Kobra wells started on schedule and within budget. The wells have been performing well since the start-up.
Re-entry to drill and complete the Volund East and South infill wells using the Transocean Arctic rig commenced in December.
The Valhall area consists of the producing fields Valhall (35.95 percent) and Hod (37.5 percent).
Production from the Valhall area increased in the fourth quarter compared to the previous quarter, mainly driven by higher performance from cyclic wells, in particular one well that produced longer than projected. Overall operations efficiency in the quarter was 89.4 percent, and plant efficiency 98.6 percent.
Coiled tubing activity to prepare wells for plug and abandonment (P&A) took place during the quarter. The new-built Maersk Invincible drilling rig will continue the P&A campaign in the first half of 2017.
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 Talisman operated Blane field and the Dong operated Oselvar field.
Production from the Ula area was lower in the fourth quarter compared with the previous quarter. This was mainly driven by deferrals due to delayed water alternating gas (WAG) wells conversion, and shut in of a well due to high pressure. Activity is ongoing to execute required pressure tests to bring the well back on line. Increasing WAG effect in combination with reinstating the shut-in well is expected to increase production in the first quarter 2017. The operation efficiency ended at 64.3 percent in the quarter due to lower wells efficiency caused by the issues described above. Plant efficiency was 84.9 percent in the fourth quarter.
The Skarv area consists of the Skarv producing field (23.84 percent). In addition, production from the Snadd test producer is reported as Skarv volumes.
Production from the Skarv area was high and stable during the fourth quarter and increased compared to the previous quarter, which was to a large extent affected by a 27-day planned shutdown in August.
The Idun and Skarv A low pressure production project was successfully completed during the quarter. This project is important to support slower decline in production profiles. Production during the first weeks in the quarter was slightly impacted by a slower ramp up than planned following the turnaround, but was thereafter stabilized at high levels. The operation efficiency ended at 90 percent in the quarter, significantly higher than previous (74 percent) caused by the planned turnaround.
Phase 1 of the Johan Sverdrup development project is progressing according to plan towards production start-up in the fourth quarter 2019. Phase 1 consists of a field center with four fixed platforms, three subsea templates, oil and gas export pipelines, power from shore and 36 production and injection wells. Most major contracts have been awarded and engineering and construction is ongoing on 22 sites.
The pre-drilling of eight oil producers with Deepsea Atlantic has been completed. Thereafter a four-well pilot/appraisal campaign was initiated for further
Commissioning, hand over and start-up preparation activities at Ivar Aasen took place throughout the fourth quarter. Production started up on December 24, without any significant incidents, bringing wells D-10 and D-16 on line in sequence. In parallel, well intervention activities continue making the remaining three pre-drilled production wells ready for hand-over and start up in the first quarter 2017.
The Maersk Interceptor drilling rig returned to Ivar Aasen late November, serving as an additional project accommodation unit. The flotel Safe Zephyrus was demobilized early February. The Maersk Interceptor jack-up rig will continue to function as an accommodation unit until drilling of additional production and injection wells which are expected to commence during March 2017.
Key activities for the Ivar Aasen project going forward are to complete all remaining construction and commissioning work before completion of offshore hook-up and commissioning planned for April 2017.
Production from Jette and Jotun ceased in December as planned.
improvement of reservoir definition, before the planned pre-drilling of nine water injection wells is expected to start in February 2017.
The full field development of the peripheral parts of the Johan Sverdrup oil field (phase 2) is also progressing according to plan and will be accompanied by an increased production capacity on a 5th platform at the field center and increased power from shore capacity that will also supply the surrounding fields Ivar Aasen, Edvard Grieg and Gina Krog. Full field production capacity is estimated to be 660 mbopd. Concept selection (DG2) is planned for the first half of 2017, Plan for Development and Operation (DG3) is planned for second half 2018 and Phase 2 production start is expected in 2022.
Aker BP is still evaluating whether the decision made by the King in Council regarding the distribution of the participating interests should be contested in the court system.
The Valhall Flank West project aims to continue infield development of the Tor formation in Valhall field in order to drain the western flank of the field. The project is expected to enter concept selection (DG2) in the first quarter 2017 and plan to pass DG3 at the end of 2017.
The development is planned as a normally unmanned installation, with 12 well slots, tied back to Valhall. Six of the 12 slots are planned as producers, with option to convert two producers into water injectors. Hence, there is spare capacity for additional future wells.
The project is planned to be executed through long term strategic frame agreements and alliances.
The North of Alvheim (NoA) area consists of Frigg Gamma Delta, Langfjellet and Frøy. With limited infrastructure available in the area, Aker BP's goal is to develop an area hub, which can tie-in neighboring licenses and open up for new exploration potential.
The area is planned to be developed with either a floating or a permanent installation as the hub, and with subsea structures or unmanned wellhead platforms on the individual reservoirs based on their size and complexity.
The project is expected to be further matured towards a planned concept selection (DG2) decision in the fourth quarter 2017.
Storklakken is planned to be developed as a stand-alone development with a single multilateral production well tied back to the Vilje template and utilizing the existing pipeline from Vilje to the Alvheim FPSO. A concept selection (DG2) is planned in the first quarter 2017 and first oil is planned for 2020.
Snadd is planned as a tie-in to Skarv FPSO in a phased development. Phase 1 is planned with three subsea wells tied in to Skarv A template, with first gas scheduled for 2020.
The key activities are development of procurement strategy for partner approval and technical qualification of the electrical heat traced pipe-in-pipe flowline. The project will be further matured towards a concept selection (DG2) decision planned during the first quarter 2017.
Oda will be developed with a subsea template tied back to the Ula field center via the Oselvar infrastructure. Recoverable reserves are estimated at 48 mmboe (gross) and the project is planned to be developed with two production wells and one water injector well. Estimated first oil is in 2019.
The Plan for Development and Operation was submitted to the the Ministry of Petroleum and Energy on November 30, 2016. Total investments for Oda are estimated at NOK 5.4 billion.
The Gina Krog field is being developed with a fixed platform with living quarters and processing facilities. Oil from Gina Krog will be exported to the markets by shuttle tankers while gas will be exported via the Sleipner platform.
The project is progressing towards a planned production start-up in the second quarter this year.
During the quarter, the company's cash spending on exploration was USD 77 million. USD 44 million was recognized as exploration expenses in the period, relating to dry wells, seismic, area fees and G&G costs.
Drilling on the Langfjellet prospect in PL442 in the North Sea was completed during the fourth quarter. The main well encountered a gross oil column of 109 meters in the Vestland Group. Three technical sidetracks were subsequently drilled to collect data.
Preliminary volume estimates for the discovery are in the range of 24 to 74 million barrels of oil equivalent. The licensees will evaluate the discovery with regards to a potential development together with other discoveries in the area. Following the successful drilling results at Langfjellet, the licensees have identified further prospectivity within the license.
In total, net resource additions from exploration was 83 mmboe in 2016, stemming from the Langfjellet discovery and the drilling campaign at Askja/Krafla.
In January 2017, the company was awarded 21 licenses in the 2016 APA (Awards in predefined areas) round, 13 as operator. The majority of the licenses are close to the company's existing core areas.
In October, Aker BP announced the acquisition of eight licenses from Tullow Norge AS, including 15 percent in the Oda (previously known as Butch) discovery in PL405. The transaction strengthens Aker BP's position in core areas surrounding the Ula, North of Alvheim, Skarv and the Askja/Krafla areas. The transaction closed in December 2016.
In a continued uncertain macro environment, Aker BP has established a strong platform for further value creation through an effective business model built on lean principles, unique technological competence and industrial cooperation.
Going forward, the company will pursue further growth opportunities both to enhance production and increase dividend capacity, while maintaining the highest standards of HSE. A dividend of USD 0.185 per share is scheduled to be paid out in February and the ambition to sustain a dividend level of minimum USD 250 million in the medium term and to increase this level once Johan Sverdrup is in production is reiterated.
The company will have up to four operated rigs in 2017. Drilling operations include production drilling at Valhall and Ivar Aasen, infill drilling at Volund, Boa and Tambar and P&A activity at Valhall. During 2017, the company plans to drill seven exploration wells in total, four operated wells and three as partner.
Aker BP plans to submit three PDO's during 2017, relating to the Valhall Flank West, Snadd and Storklakken projects.
The company has a robust balance sheet with USD 2.5 billion in available liquidity, providing the company with ample financial flexibility. Going forward, the company will work to improve the efficiency and effectiveness of its capital and debt structure.
Aker BP expects to produce between 128 and 135 mboepd in 2017 with a production cost of approximately 11 USD/boe. The full year 2017 CAPEX is expected to be between USD 900 – 950 million, exploration expenditures are expected to be USD 280 – 300 million and decommissioning costs between USD 100 – 110 million.
| Group | |||||
|---|---|---|---|---|---|
| Q4 | 01.01.-31.12. | ||||
| (USD 1 000) | Note | 2016 | 2015 | 2016 | 2015 |
| Petroleum revenues | 2 | 541 550 | 218 314 | 1 260 803 | 1 158 683 |
| Other income | 2 | 114 074 | 36 320 | 103 326 | 63 119 |
| Total income | 655 624 | 254 634 | 1 364 129 | 1 221 802 | |
| Exploration expenses | 3 | 44 281 | 18 867 | 147 453 | 76 404 |
| Production costs | 121 139 | 24 077 | 226 818 | 141 000 | |
| Depreciation | 5 | 159 796 | 111 590 | 509 027 | 480 959 |
| Impairments | 4, 5 | 44 627 | 191 939 | 71 375 | 430 468 |
| Other operating expenses | 5 029 | 3 228 | 21 993 | 51 608 | |
| Total operating expenses | 374 872 | 349 701 | 976 665 | 1 180 438 | |
| Operating profit/loss | 280 752 | -95 067 | 387 464 | 41 364 | |
| Interest income | 2 887 | 1 739 | 5 795 | 3 098 | |
| Other financial income | 20 625 | 1 815 | 42 871 | 65 385 | |
| Interest expenses | 20 229 | 23 047 | 82 161 | 82 774 | |
| Other financial expenses | 73 855 | 36 645 | 63 515 | 140 679 | |
| Net financial items | 6 | -70 572 | -56 138 | -97 011 | -154 971 |
| Profit/loss before taxes | 210 180 | -151 205 | 290 453 | -113 607 | |
| Taxes (+)/tax income (-) | 7 | 277 183 | 4 980 | 255 482 | 199 045 |
| Net profit/loss | -67 003 | -156 184 | 34 971 | -312 652 | |
| Weighted average no. of shares outstanding and fully diluted Earnings/(loss) after tax per share |
337 737 071 -0.20 |
202 618 602 -0.77 |
236 582 807 0.15 |
202 618 602 -1.54 |
| Group | ||||||
|---|---|---|---|---|---|---|
| Q4 | 01.01.-31.12. | |||||
| (USD 1 000) | Note | 2016 | 2015 | 2016 | 2015 | |
| Profit/loss for the period | -67 003 | -156 184 | 34 971 | -312 652 | ||
| Items which will not be reclassified over profit and loss (net of taxes) | ||||||
| Currency translation adjustment | - | - | -59 | - | ||
| Actuarial gain/loss pension plan | - | 17 | - | 17 | ||
| Total comprehensive income in period | -67 003 | -156 168 | 34 911 | -312 636 |
| Group | ||||
|---|---|---|---|---|
| (USD 1 000) | Note | 31.12.2016 | 31.12.2015 | |
| ASSETS | ||||
| Intangible assets | ||||
| Goodwill | 5 | 1 846 971 | 767 571 | |
| Capitalized exploration expenditures | 5 | 395 260 | 289 980 | |
| Other intangible assets | 5 | 1 332 813 | 648 030 | |
| Tangible fixed assets | ||||
| Property, plant and equipment | 5 | 4 441 796 | 2 979 434 | |
| Financial assets | ||||
| Long-term receivables | 47 171 | 3 782 | ||
| Other non-current assets | 8 | 12 894 | 12 628 | |
| Total non-current assets | 8 076 905 | 4 701 425 | ||
| Inventories | ||||
| Inventories | 69 434 | 31 533 | ||
| Receivables | ||||
| Accounts receivable | 170 000 | 85 546 | ||
| Other short-term receivables | 9 | 422 932 | 105 190 | |
| Other current financial assets | - | 2 907 | ||
| Tax receivables | 7 | 400 638 | 126 391 | |
| Short-term derivatives | 12 | - | 45 217 | |
| Cash and cash equivalents | ||||
| Cash and cash equivalents | 10 | 115 286 | 90 599 | |
| Total current assets | 1 178 290 | 487 384 | ||
| TOTAL ASSETS | 9 255 196 | 5 188 809 |
| Group | ||||
|---|---|---|---|---|
| (USD 1 000) | Note | 31.12.2016 | 31.12.2015 | |
| EQUITY AND LIABILITIES | ||||
| Equity | ||||
| Share capital | 11 | 54 349 | 37 530 | |
| Share premium | 3 150 567 | 1 029 617 | ||
| Other equity | -755 709 | -728 121 | ||
| Total equity | 2 449 207 | 339 026 | ||
| Non-current liabilities | ||||
| Deferred taxes | 7 | 1 045 542 | 1 356 114 | |
| Long-term abandonment provision | 16 | 2 080 940 | 412 805 | |
| Provisions for other liabilities | 218 562 | 1 638 | ||
| Long-term bonds | 14 | 510 337 | 503 440 | |
| Other interest-bearing debt | 15 | 2 030 209 | 2 118 935 | |
| Long-term derivatives | 12 | 35 659 | 62 012 | |
| Current liabilities | ||||
| Trade creditors | 88 156 | 51 078 | ||
| Accrued public charges and indirect taxes | 39 048 | 9 060 | ||
| Tax payable | 7 | 92 661 | - | |
| Short-term derivatives | 12 | 5 049 | 13 506 | |
| Short-term abandonment provision | 16 | 75 981 | 10 520 | |
| Other current liabilities | 13 | 583 844 | 310 675 | |
| Total liabilities | 6 805 988 | 4 849 783 | ||
| TOTAL EQUITY AND LIABILITIES | 9 255 196 | 5 188 809 |
| Other equity | ||||||||
|---|---|---|---|---|---|---|---|---|
| Other comprehensive income | ||||||||
| (USD 1 000) | Share capital | Share premium |
Other paid-in capital |
Actuarial gains/(losses) |
Foreign currency translation reserves* |
Retained earnings |
Total other equity |
Total equity |
| Equity as of 31.12.2014 | 37 530 | 1 029 617 | 573 083 | -105 | -115 491 | -872 972 | -415 485 | 651 662 |
| Profit/loss for the period 01.01.2015 - 31.12.2015 | - | - | - | 17 | - | -312 652 | -312 636 | -312 636 |
| Equity as of 31.12.2015 | 37 530 | 1 029 617 | 573 083 | -88 | -115 491 | -1 185 625 | -728 121 | 339 026 |
| Private placement | 16 820 | 2 120 950 | - | - | - | - | - | 2 137 769 |
| Dividend distributed | - | - | - | - | - | -62 500 | -62 500 | -62 500 |
| Profit/loss for the period 01.01.2016 - 31.12.2016 | - | - | - | - | -59 | 34 971 | 34 911 | 34 911 |
| Equity as of 31.12.2016 | 54 349 | 3 150 567 | 573 083 | -88 | -115 550 | -1 213 154 | -755 709 | 2 449 207 |
* At 15 October 2014, the presentation currency was changed to USD retrospectively as if USD had always been the presentation currency. For each category of the opening equity as at 1 January 2013, the historical rates were used for translation to USD, and therefore an exchange reserve was established which represents the fact that the presentation currency is different from the functional currency in the periods presented prior to the change in functional currency to USD as at 15 October 2014. For each period presented prior to the change in functional currency, the ending balance of total equity is translated to USD using the end rate.
| Group | ||||||
|---|---|---|---|---|---|---|
| Q4 | 01.01.-31.12. | Year | ||||
| (USD 1 000) | Note | 2016 | 2015 | 2016 | 2015 | |
| CASH FLOW FROM OPERATING ACTIVITIES | ||||||
| Profit/loss before taxes | 210 180 | -151 205 | 290 453 | -113 607 | ||
| Taxes paid during the period | - | -85 397 | -1 419 | -320 618 | ||
| Tax refund during the period | 129 278 | 87 662 | 212 944 | 87 662 | ||
| Depreciation | 5 | 159 796 | 111 590 | 509 027 | 480 959 | |
| Net impairment losses | 4, 5 | 44 627 | 191 939 | 71 375 | 430 468 | |
| Accretion expenses | 6, 16 | 29 285 | 6 746 | 47 977 | 26 351 | |
| Interest expenses | 6 | 42 693 | 37 109 | 160 808 | 127 620 | |
| Interest paid | -52 316 | -44 847 | -161 634 | -124 276 | ||
| Changes in derivatives | 2, 6 | 43 548 | -2 222 | 10 408 | -793 | |
| Amortized loan costs | 6 | 5 672 | 2 262 | 17 915 | 17 480 | |
| Gain on change of pension scheme | 2 | -115 616 | - | -115 616 | - | |
| Amortization of fair value of contracts assumed in the | ||||||
| Marathon acquisition | - | - | - | -2 878 | ||
| Expensed capitalized dry wells | 3, 6 | 7 968 | 2 492 | 51 669 | 11 682 | |
| Changes in inventories, accounts payable and receivables | -225 400 | -28 314 | -317 488 | -13 060 | ||
| Changes in abandonment liabilities through income statement | -1 131 | -1 569 | -1 131 | -1 569 | ||
| Changes in other current balance sheet items | 41 609 | -4 474 | 120 365 | 81 048 | ||
| NET CASH FLOW FROM OPERATING ACTIVITIES | 320 192 | 121 772 | 895 652 | 686 467 | ||
| CASH FLOW FROM INVESTMENT ACTIVITIES | ||||||
| Payment for removal and decommissioning of oil fields | 16 | -6 743 | -3 741 | -12 237 | -12 508 | |
| Disbursements on investments in fixed assets | 5 | -244 267 | -229 028 | -935 755 | -917 150 | |
| Net of cash consideration paid for, and cash acquired from, BP Norge AS | - | - | 423 990 | - | ||
| Acquisition of Premier Oil Norge AS (net of cash acquired) | - | -125 600 | - | -125 600 | ||
| Disbursements on investments in capitalized exploration expenditures and | ||||||
| other intangible assets | 5 | -62 034 | -80 959 | -181 492 | -113 051 | |
| NET CASH FLOW FROM INVESTMENT ACTIVITIES | -313 045 | -439 328 | -705 494 | -1 168 310 | ||
| CASH FLOW FROM FINANCING ACTIVITIES | ||||||
| Repayment of short-term debt | - | -70 938 | - | -70 938 | ||
| Repayment of long-term debt | -612 825 | - | -612 825 | -330 000 | ||
| Net proceeds from issuance of long-term debt | - | 275 000 | 512 013 | 685 620 | ||
| Paid dividend | -62 500 | - | -62 500 | - | ||
| NET CASH FLOW FROM FINANCING ACTIVITIES | -675 325 | 204 062 | -163 312 | 284 683 | ||
| Net change in cash and cash equivalents | -668 178 | -113 493 | 26 846 | -197 160 | ||
| Cash and cash equivalents at start of period | 785 622 | 206 941 | 90 599 | 296 244 | ||
| Effect of exchange rate fluctuation on cash held | -2 158 | -2 849 | -2 158 | -8 485 | ||
| CASH AND CASH EQUIVALENTS AT END OF PERIOD | 10 | 115 286 | 90 599 | 115 286 | 90 599 | |
| SPECIFICATION OF CASH EQUIVALENTS AT END OF PERIOD | ||||||
| Bank deposits and cash | 106 369 | 86 201 | 106 369 | 86 201 | ||
| Restricted bank deposits | 8 917 | 4 398 | 8 917 | 4 398 | ||
| CASH AND CASH EQUIVALENTS AT END OF PERIOD | 10 | 115 286 | 90 599 | 115 286 | 90 599 |
(All figures in USD 1 000)
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 2015. These interim financial statements have not been subject to review or audit by independent auditors.
The acquisition of BP Norge AS was completed on 30 September 2016, and the activity of BP Norge is thus fully included in this report. On 1 December 2016, the activity in BP Norge AS was transferred to Aker BP ASA.
The accounting principles used for this interim report are in all material respect consistent with the principles used in the financial statements for 2015. There are no new standards effective from 1 January 2016.
The group changed the presentation of accretion expenses in Q1 2016. It is now included in the line item other financial expenses, while it has been presented as interest expenses prior to 2016. In addition, following the change from defined benefit to defined contribution scheme, pension is no longer presented on a separate line in the Statement of financial position. Comparable figures have been restated accordingly.
| Group | ||||
|---|---|---|---|---|
| Q4 | 01.01.-31.12. | |||
| Breakdown of petroleum revenues (USD 1 000) | 2016 | 2015 | 2016 | 2015 |
| Recognized income liquids | 459 730 | 197 491 | 1 120 094 | 1 044 548 |
| Recognized income gas | 76 684 | 19 938 | 128 436 | 110 909 |
| Tariff income | 5 136 | 884 | 12 274 | 3 227 |
| Total petroleum revenues | 541 550 | 218 314 | 1 260 803 | 1 158 683 |
| Breakdown of produced volumes (barrels of oil equivalent) | ||||
| Liquids | 9 076 017 | 4 419 414 | 23 830 388 | 19 307 898 |
| Gas | 2 563 841 | 548 240 | 4 512 648 | 2 593 733 |
| Total produced volumes | 11 639 859 | 4 967 654 | 28 343 036 | 21 901 630 |
| Other income (USD 1 000) | ||||
| Realized gain/loss (-) on oil derivatives | 1 497 | 14 758 | 30 199 | 14 962 |
| Unrealized gain/loss (-) on oil derivatives | -2 963 | 20 664 | -46 399 | 45 217 |
| Gain on license transactions | 20 | 856 | 20 | 856 |
| Other income* | 115 520 | 42 | 119 506 | 2 084 |
| Total other income | 114 074 | 36 320 | 103 326 | 63 119 |
* Other income are related to change in pension scheme for employees in BP Norge AS. As of 30 September 2016 there was a defined benefit scheme in BP Norge AS, which has been replaced by a defined contribution scheme during Q4 2016. The accounting consequences of the settlement are that previous gross pension liability is reset to zero and pension funds are used to issue an insurance policy to each employee.
The group changed its presentation of commodity derivatives in Q4 2015. Gains and losses are now presented as other operating income, while it was included in financial items prior to Q4 2015. Comparable figures have been restated accordingly.
| Group | |||||
|---|---|---|---|---|---|
| Q4 | 01.01.-31.12. | ||||
| Breakdown of exploration expenses (USD 1 000) | 2016 | 2015 | 2016 | 2015 | |
| Seismic | 18 316 | 259 | 29 321 | 12 530 | |
| Area fee | 4 036 | 3 286 | 13 291 | 8 634 | |
| Expensed capitalized wells this year | 7 968 | 2 492 | 41 284 | 10 390 | |
| Expensed capitalized wells previous years | - | - | 10 385 | 1 292 | |
| Other exploration expenses | 13 961 | 12 830 | 53 171 | 43 559 | |
| Total exploration expenses | 44 281 | 18 867 | 147 453 | 76 404 |
In Q1 2016 the group did some changes in the subcategories within exploration expenses presented above. Comparable figures have been restated accordingly.
Impairment tests of individual cash-generating units are performed when impairment triggers are identified, and for goodwill impairment is tested at least annually. In Q4 2016 two categories of impairment tests have been performed:
Impairment test of fixed assets and related intangible assets, other than goodwill
Impairment test of goodwill
Impairment is recognized when the book value of an asset or a cash-generating unit, including associated goodwill, exceeds the recoverable amount. The recoverable amount is the higher of the asset's fair value less cost to sell and value in use. For assets and goodwill in the Group prior to the acquisition of BP Norge AS, the impairment testing has been based on value in use, consistent with the impairment testing in Q1 - Q3 2016. For assets and goodwill recognized in relation to the acquisition of BP Norge AS, the impairment testing has been based on fair value. For both value in use and fair value, the impairment testing is done based on discounted cash flows. The expected future cash flow is discounted to the net present value by applying a discount rate after tax that reflects the current market valuation of the time value of money, and the specific risk related to the asset. The discount rate is derived from the weighted average cost of capital (WACC) for a market participant. Cash flows are projected for the estimated lifetime of the fields, which may exceed periods greater than five years. If not specifically stated otherwise, the same assumptions have been applied for value in use and fair value testing.
For producing licences and licences in the development phase, recoverable amount is estimated based on discounted future after tax cash flows. Below is an overview of the key assumptions applied for impairment testing purposes as of 31 December 2016.
Future price level is a key assumption and has significant impact on the net present value. Forecasted oil and gas prices are based on the management's estimates and available market data. Information about market prices in the near future can be derived from the futures contract market. The information about future prices is less reliable on a long-term basis, as there are fewer observable market transactions going forward. In the impairment test, the oil price is therefore based on the forward curve from the beginning of 2017 to the end of 2019. From 2020, the oil price is based on the company's long-term price assumptions.
The nominal oil price based on the forward curve applied in the impairment test is as follows:
| Year | USD/BOE |
|---|---|
| 2017 | 58.5 |
| 2018 | 58.5 |
| 2019 | 58.0 |
| From 2020 (in real terms) - fair value testing* | 65.0 |
| From 2020 (in real terms) - value in use testing | 75.0 |
* In line with the fair value requirements in IAS 36, as defined by IFRS 13 definition of fair value, the long-term fair value oil price assumption reflects the view of market participants at the measurement date under current market conditions.
Future cash flows are calculated on the basis of expected production profiles and estimated proven and probable remaining reserves. The recoverable amount is sensitive to changes in reserves.
The post tax nominal discount rate is set to 7.5 per cent, which is a change from 8.5 per cent from previous quarters in 2016.
| Year | USD/NOK |
|---|---|
| 2017 | 8.59 |
| 2018 | 8.53 |
| 2019 | 8.46 |
| From 2020 | 7.50 |
The long-term inflation rate is assumed to be 2.5 per cent.
| Impairment charged/reversal | Recoverable amount/ | |||
|---|---|---|---|---|
| Cash generating unit (USD 1 000) | Intangible | Tangible | carrying value | |
| CGU's with no remaining carrying value | - | -6 739 | - | |
| Total | - | -6 739 | - |
The reason for the reversals is reduced ARO liabilities on CGUs with no remaining carrying value. The reduction is thus charged directly to the Income Statement.
For the CGUs Alvheim and Skarv/Snadd, no impairment is recognized during Q4. For the CGUs Ula/Tambar and Valhall/Hod, the impairment charge has been calculated as follows:
| (USD 1 000) | Ula/Tambar | Valhall/Hod |
|---|---|---|
| Net carrying value | 264 960 | 1 112 465 |
| Recoverable amount (including tax amortization benefit) | 235 551 | 1 090 508 |
| Impairment charge Q4 | 29 409 | 21 957 |
The main reasons for the impairment is the reduction of the deferred tax, as well as a general field update.
The table below shows how the impairment of goodwill allocated to the Ula/Tambar and Valhall/Hod would be affected by changes in the various assumptions, given that the remainders of the assumptions are constant.
| Change in goodwill impairment after | |||||
|---|---|---|---|---|---|
| Assumption (USD 1 000) | Change | Increase in assumption Decrease in assumption |
|||
| Oil and gas price | +/- 20% | -51 366 | 407 227 | ||
| Production profiles (reserves) | +/- 5% | -51 366 | 103 151 | ||
| Discount rate | +/- 1% point | 60 010 | -25 170 | ||
| Currency rate USD/NOK | +/- 1.0 NOK | -51 366 | 92 536 | ||
| Inflation | +/- 1% point | -39 489 | 83 553 |
| Production | Fixtures and | |||
|---|---|---|---|---|
| (USD 1 000) | Assets under development |
facilities including wells |
fittings, office machinery |
Total |
| Book value 31.12.2015 | 1 493 795 | 1 470 881 | 14 758 | 2 979 434 |
| Acquisition cost 31.12.2015 | 1 505 779 | 2 514 487 | 35 506 | 4 055 772 |
| Acquisition of BP Norge AS | - | 921 081 | - | 921 081 |
| Additions | 656 032 | 93 991 | 7 931 | 757 954 |
| Disposals | - | - | 91 | 91 |
| Reclassification | -41 615 | 29 711 | 11 825 | -79 |
| Acquisition cost 30.9.2016 | 2 120 197 | 3 559 271 | 55 171 | 5 734 638 |
| Accumulated depreciation and impairments 31.12. 2015 | 11 984 | 1 043 606 | 20 748 | 1 076 338 |
| Depreciation | - | 281 040 | 3 864 | 284 904 |
| Impairment | -10 418 | 548 | - | -9 870 |
| Retirement/transfer depreciations | - | 157 | - | 157 |
| Accumulated depreciation and impairments 30.9.2016 | 1 566 | 1 325 351 | 24 612 | 1 351 529 |
| Book value 30.9.2016 | 2 118 630 | 2 233 920 | 30 559 | 4 383 110 |
| Acquisition cost 30.9.2016 | 2 120 197 | 3 559 271 | 55 171 | 5 734 638 |
| Additions | 96 762 | 83 154 | 4 672 | 184 588 |
| Disposals | - | - | 3 909 | 3 909 |
| Reclassification* | -1 308 285 | 1 308 142 | 203 | 61 |
| Acquisition cost 31.12.2016 | 908 674 | 4 950 566 | 56 137 | 5 915 377 |
| Accumulated depreciation and impairments 30.9.2016 | 1 566 | 1 325 351 | 24 612 | 1 351 529 |
| Depreciation | - | 130 360 | 2 627 | 132 987 |
| Impairment | - | -6 739 | - | -6 739 |
| Retirement/transfer depreciations | - | -313 | -3 882 | -4 195 |
| Accumulated depreciation and impairments 31.12.2016 | 1 566 | 1 448 659 | 23 357 | 1 473 582 |
| Book value 31.12.2016 | 907 108 | 3 501 908 | 32 779 | 4 441 796 |
* The reclassification is related to Viper/Kobra (Alvheim) and Ivar Aasen which entered into production phase in Q4 2016.
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.
See Note 4 for information regarding impairment charges.
| Other intangible assets | Exploration | |||||||
|---|---|---|---|---|---|---|---|---|
| (USD 1 000) | Licences etc. | Software | Total | wells | Goodwill | |||
| Book value 31.12.2015 | 646 487 | 1 543 | 648 030 | 289 980 | 767 571 | |||
| Acquisition cost 31.12.2015 | 789 316 | 9 149 | 798 465 | 289 980 | 1 561 880 | |||
| Acquisition of BP Norge AS | 759 962 | - | 759 962 | - | 1 119 083 | |||
| Additions | 4 608 | -1 383 | 3 225 | 116 155 | ||||
| Disposals/expensed dry wells | - | - | - | 43 702 | - | |||
| Reclassification | 816 | - | 816 | -737 | ||||
| Acquisition cost 30.9.2016 | 1 554 702 | 7 766 | 1 562 468 | 361 696 | 2 680 963 | |||
| Accumulated depreciation and impairments 31.12. 2015 | 142 829 | 7 606 | 150 435 | - | 794 309 | |||
| Depreciation | 64 516 | -188 | 64 327 | - | - | |||
| Impairment | 8 429 | - | 8 429 | - | 28 189 | |||
| Retirement/transfer depreciations | -156 | - | -156 | - | - | |||
| Accumulated depreciation and impairments 30.9.2016 | 215 618 | 7 417 | 223 035 | - | 822 498 | |||
| Book value 30.9.2016 | 1 339 084 | 349 | 1 339 433 | 361 696 | 1 858 465 | |||
| Acquisition cost 30.9.2016 | 1 554 702 | 7 766 | 1 562 468 | 361 696 | 2 680 963 | |||
| Additions* | 20 912 | - | 20 912 | 41 182 | 39 871 | |||
| Disposals/expensed dry wells | - | 265 | 265 | 7 968 | - | |||
| Reclassification | -410 | - | -410 | 350 | - | |||
| Acquisition cost 31.12.2016 | 1 575 203 | 7 501 | 1 582 705 | 395 260 | 2 720 835 | |||
| Accumulated depreciation and impairments 30.9.2016 | 215 618 | 7 417 | 223 035 | - | 822 498 | |||
| Depreciation | 26 739 | 70 | 26 809 | - | - | |||
| Impairment | - | - | - | - | 51 366 | |||
| Retirement/transfer depreciations | 313 | -265 | 48 | - | - | |||
| Accumulated depreciation and impairments 31.12.2016 | 242 670 | 7 223 | 249 892 | - | 873 864 | |||
| Book value 31.12.2016 | 1 332 534 | 279 | 1 332 813 | 395 260 | 1 846 971 |
* As described in note 3 to the Q3 Financial Statements, the Purchase Price Allocation related to the acquisition of BP Norge AS was based on currently available information about fair values at the acquisition date 30 September 2016. The allocation may be changed if new information becomes available within 12 months from the acquisition date. During Q4 the Group has received information indicating an increase in Asset Retirement Obligation, an increase in deferred tax asset and an increase in goodwill. This is the background for the additions in goodwill in Q4 in the table above.
See Note 4 for information regarding impairment charges.
| Group | ||||
|---|---|---|---|---|
| Q4 | 01.01.-31.12. | |||
| Depreciation in the Income statement (USD 1 000) | 2016 | 2015 | 2016 | 2015 |
| Depreciation of tangible fixed assets | 132 987 | 94 530 | 417 891 | 405 869 |
| Depreciation of intangible assets | 26 809 | 17 061 | 91 136 | 75 090 |
| Total depreciation in the Income statement | 159 796 | 111 590 | 509 027 | 480 959 |
| Impairment in the Income statement (USD 1 000) | ||||
| Impairment/reversal of tangible fixed assets | -6 739 | 3 092 | -16 609 | 3 092 |
| Impairment/reversal of intangible fixed assets | - | 2 832 | 8 429 | 2 832 |
| Impairment of goodwill | 51 366 | 186 016 | 79 555 | 424 544 |
| Total impairment in the Income statement | 44 627 | 191 939 | 71 375 | 430 468 |
| Group | ||||
|---|---|---|---|---|
| Q4 | 01.01.-31.12. | |||
| (USD 1 000) | 2016 | 2015 | 2016 | 2015 |
| Interest income | 2 887 | 1 739 | 5 795 | 3 098 |
| Realised gains on derivatives | 601 | 1 800 | 3 138 | 2 679 |
| Return on financial investments | - | 15 | - | 39 |
| Change in fair value of derivatives | - | - | 35 991 | 18 250 |
| Currency gains | 20 024 | - | 3 742 | 44 416 |
| Total other financial income | 20 625 | 1 815 | 42 871 | 65 385 |
| Interest expenses | 42 693 | 37 109 | 160 808 | 127 620 |
| Capitalized interest cost, development projects | -28 136 | -16 325 | -96 562 | -62 326 |
| Amortized loan costs | 5 672 | 2 262 | 17 915 | 17 480 |
| Total interest expenses | 20 229 | 23 047 | 82 161 | 82 774 |
| Currency losses | - | 3 256 | - | - |
| Realised loss on derivatives | 1 466 | 8 138 | 7 675 | 51 584 |
| Change in fair value of derivatives | 40 585 | 18 505 | - | 62 739 |
| Accretion expenses | 29 285 | 6 746 | 47 977 | 26 351 |
| Other financial expenses | 2 519 | 7 864 | 6 | |
| Total other financial expenses | 73 855 | 36 645 | 63 515 | 140 679 |
| Net financial items | -70 572 | -56 138 | -97 011 | -154 971 |
The group changed the presentation of accretion expenses in Q1 2016. It is now included in the line item other financial expenses, while it was presented as interest expenses prior to 2016. Comparable figures have been restated accordingly.
| Group | ||||
|---|---|---|---|---|
| Q4 | 01.01.-31.12. | |||
| Taxes for the period appear as follows (USD 1 000) | 2016 | 2015 | 2016 | 2015 |
| Calculated current year tax/exploration tax refund | -114 769 | -17 431 | -131 488 | 49 776 |
| Change in deferred taxes in the Income statement | 384 351 | 22 509 | 374 617 | 153 927 |
| Prior period adjustments | 7 601 | -98 | 12 353 | -4 658 |
| Total taxes (+)/tax income (-) | 277 183 | 4 980 | 255 482 | 199 045 |
| Group | ||
|---|---|---|
| Calculated tax receivable (+)/tax payable (-) (USD 1 000) | 31.12.2016 | 31.12.2015 |
| Tax receivable/payable at 1.1. | 126 391 | -189 098 |
| Current year tax (-)/tax receivable (+) | 131 488 | -49 776 |
| Tax receivable related to acquisitions | 255 873 | 108 047 |
| Tax payment/tax refund | -211 525 | 232 956 |
| Prior period adjustments | -1 681 | 11 580 |
| Revaluation of tax receivable | 7 430 | 12 682 |
| Total tax receivable (+)/tax payable (-) | 307 977 | 126 391 |
| Tax receivable included as current assets (+) | 400 638 | 126 391 |
| Tax payable included as current liabilities (-) | -92 661 | - |
| Group | |||
|---|---|---|---|
| Deferred taxes (-)/deferred tax asset (+) (USD 1 000) | 31.12.2016 | 31.12.2015 | |
| Deferred taxes/deferred tax asset 1.1. | -1 356 114 | -1 286 357 | |
| Change in deferred taxes in the Income statement | -374 617 | -153 927 | |
| Reclassification of loss carried forward from Premier Oil Norge AS and BP Norge AS | -238 866 | - | |
| Deferred tax related to acquisitions* | 942 611 | 91 151 | |
| Prior period adjustment | -18 555 | -6 921 | |
| Deferred tax charged to OCI and equity | -1 | -59 | |
| Net deferred tax (-)/deferred tax asset (+) | -1 045 542 | -1 356 114 | |
| Deferred tax (-) | -1 045 542 | -1 356 114 |
* Deferred tax asset from BP Norge AS has been netted against deferred tax liability in Aker BP as the activity in BP Norge AS was transferred to Aker BP during the quarter.
| Group | |||||
|---|---|---|---|---|---|
| Q4 | 01.01.-31.12. | ||||
| Reconciliation of tax expense (USD 1 000) | 2016 | 2015 | 2016 | 2015 | |
| 25%/27% group tax on profit before tax | 52 545 | -40 825 | 72 613 | -30 674 | |
| 53%/51% special tax on profit before tax | 111 395 | -77 114 | 153 940 | -57 940 | |
| Tax effect on uplift | -27 591 | -22 406 | -103 313 | -93 513 | |
| Change in tax rates* | -2 888 | 265 | -2 888 | 265 | |
| Permanent difference on impairment | 40 065 | 146 579 | 62 053 | 332 631 | |
| Foreign currency translation of NOK monetary items | -8 527 | -27 410 | 2 163 | -59 857 | |
| Foreign currency translation of USD monetary items | -125 049 | -37 092 | 55 692 | -243 175 | |
| Tax effect of financial and other 25%/27% items | 82 879 | 41 028 | -21 335 | 185 202 | |
| Revaluation of tax balances** | 146 751 | 18 390 | 28 901 | 164 348 | |
| Utilization of acquired loss carried forward | - | -5 524 | - | -5 524 | |
| Other items (other permanent differences and prior period adjustment) | 7 602 | 9 090 | 7 656 | 7 282 | |
| Total taxes (+)/tax income (-) | 277 183 | 4 980 | 255 482 | 199 045 |
* The tax rate for general corporation tax changed from 25 to 24 per cent from 1 January 2017. The rate for special tax changed from the same date from 53 to 54 per cent.
** 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).
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.
The revaluation of tax receivable and payable is presented as foreign exchange loss/gain in the Income statement, while the impact on deferred tax from revaluation of tax balances is presented as tax.
| Group | |||
|---|---|---|---|
| (USD 1 000) | 31.12.2016 | 31.12.2015 | |
| Shares in Alvheim AS | 10 | 10 | |
| Shares in Det norske oljeselskap AS | 1 021 | 1 021 | |
| Shares in Sandvika Fjellstue AS | 1 814 | 1 814 | |
| Investment in subsidiaries | 2 845 | 2 845 | |
| Tenancy deposit | 1 553 | 1 512 | |
| Other non-current assets | 8 496 | 8 272 | |
| Total other non-current assets | 12 894 | 12 628 |
Alvheim AS, Det norske oljeselskap AS (previously Marathon Oil Norge AS) and Sandvika Fjellstue AS have been deemed immaterial for consolidation purposes.
The acquisition of BP Norge AS was completed at 30 September 2016 and the company is consolidated in this report. Det norske oil AS and Det norske Exploration AS were liquidated during Q2 2016.
| Group | ||
|---|---|---|
| (USD 1 000) | 31.12.2016 | 31.12.2015 |
| Pre-payments | 40 730 | 21 634 |
| VAT receivable | 7 913 | 6 121 |
| Underlift of petroleum | 70 003 | 3 696 |
| Accrued income from sale of petroleum products | 86 429 | 1 866 |
| Other receivables, mainly from licenses | 217 857 | 71 873 |
| Total other short-term receivables | 422 932 | 105 190 |
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) | 31.12.2016 | 31.12.2015 |
| Bank deposits | 106 369 | 86 201 |
| Restricted funds (tax withholdings) | 8 917 | 4 398 |
| Cash and cash equivalents | 115 286 | 90 599 |
| Unused revolving credit facility (see Note 15) | 550 000 | 550 000 |
| Unused reserve-based lending facility (see Note 15) | 1 805 000 | 731 370 |
| Group | |||
|---|---|---|---|
| (USD 1 000) | 31.12.2016 | 31.12.2015 | |
| Share capital | 54 349 | 37 530 | |
| Total number of shares (in 1 000) | 337 737 | 202 619 | |
| Nominal value per share in NOK | 1.00 | 1.00 |
The group completed a private placement in Q3 2016, increasing the number of outstanding shares with 135.1 million to 337.7 million shares. The additional shares have a nominal value of NOK 1 and a share premium value of NOK 126 per share.
| Group | ||
|---|---|---|
| (USD 1 000) | 31.12.2016 | 31.12.2015 |
| Unrealized gain commodity derivatives | - | 45 217 |
| Short-term derivatives included in assets | - | 45 217 |
| Total derivatives included in assets | - | 45 217 |
| Unrealized losses currency contracts | 5 073 | 7 840 |
| Unrealized losses interest rate swaps | 30 586 | 54 172 |
| Long-term derivatives included in liabilities | 35 659 | 62 012 |
| Unrealized losses currency contracts | 3 868 | 13 506 |
| Unrealized losses commodity derivatives | 1 181 | - |
| Short-term derivatives included in liabilities | 5 049 | 13 506 |
| Total derivatives included in liabilities | 40 708 | 75 518 |
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 contracts 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.
| Group | |||
|---|---|---|---|
| Breakdown of other current liabilities (USD 1 000) | 31.12.2016 | 31.12.2015 | |
| Current liabilities related to overcall in licences | 81 686 | 33 444 | |
| Share of other current liabilities in licences | 360 222 | 184 010 | |
| Overlift of petroleum | 20 000 | 17 088 | |
| Fair value of contracts assumed in acquisition of Marathon Oil / BP Norge AS* | 36 199 | 12 009 | |
| Other current liabilities** | 85 737 | 64 125 | |
| Total other current liabilities | 583 844 | 310 675 |
* The negative contracts value are related to rig contracts entered into by Marathon Oil Norge AS and BP Norge AS, which was different from current market terms at the time of acquisition. The fair value was based on the difference between market price and contract price. 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.
** Other current liabilities includes unpaid wages and vacation pay, accrued interest and other provisions.
| Group | |||
|---|---|---|---|
| (USD 1 000) | 31.12.2016 | 31.12.2015 | |
| DETNOR02 Senior unsecured bond1) | 214 827 | 208 744 | |
| DETNOR03 Subordinated PIK toggle bond 2) | 295 510 | 294 696 | |
| Total bond | 510 337 | 503 440 |
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.
In October 2016 the group removed the dividend restriction, subject to a leverage incurrence test at 4.5x (net interest-bearing debt / EBITDAX). In addition, the bondholders have received a put option for an amount corresponding to any dividend payment from Aker BP at put price of 107. As compensation, the DETNOR02 bonds will be repaid at 107 per cent of par at maturity in 2020, up from the previous 104 per cent resulting from the covenant amendment process earlier this year.
2) In May 2015, the group completed an issue of USD 300 million subordinated seven year PIK Toggle bonds with a fixed rate coupon of 10.25 per cent. The bonds are callable and includes an option to defer interest payments.
| Group | |||
|---|---|---|---|
| (USD 1 000) | 31.12.2016 | 31.12.2015 | |
| Reserve-based lending facility | 2 030 209 | 2 118 935 | |
| Total other interest-bearing debt | 2 030 209 | 2 118 935 |
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.
The interest rate is from 1 - 6 months LIBOR plus a margin of 2.75 per cent, with a utilization fee of 0.5 per cent on outstanding loan. In addition, a commitment fee of 1.1 per cent is paid on unused credit.
The borrowing base availability in the second half of 2016 was reset to USD 2.9 billion (up from USD 2.8 billion in the first half of 2016). After the inclusion of the BP Norge assets into the RBL facility and the semi-annual re-determination in December 2016, the borrowing base was increased to USD 3.9 billion as of 31 December 2016.
A revolving credit facility ("RCF") of USD 550 million was completed with a consortium of banks in June 2015. The loan has a tenor of four years with extension options of one plus one year at the lenders discretion. The loan carries a margin of 4 per cent, stepping up by 0.5 per cent annually after 3, 4 and 5 years, plus a utilization fee of 1.5 per cent. In addition, a commitment fee of 2.0 per cent is paid on unused credit. This facility is undrawn as of 31 December 2016.
In October 2016, the group completed a process with its bank consortium in order to amend certain provisions of the RBL and RCF, including removal of the dividend restrictions, subject to a leverage incurrence test of 4.5x (net interest-bearing debt / EBITDAX).
| Group | ||
|---|---|---|
| (USD 1 000) | 31.12.2016 | 31.12.2015 |
| Provisions as of 1 January | 423 325 | 489 051 |
| Abandonment liabilities from acquisition of BP Norge AS* | 1 680 206 | - |
| Incurred cost removal | -12 237 | -12 508 |
| Accretion expense - present value calculation | 47 977 | 26 351 |
| Change in estimates and incurred liabilities on new fields | 17 650 | -79 569 |
| Total provision for abandonment liabilities | 423 325 | |
| Break down of the provision to short-term and long-term liabilities | ||
| Short-term | 75 981 | 10 520 |
| Long-term | 2 080 940 | 412 805 |
| Total provision for abandonment liabilities | 2 156 921 | 423 325 |
* Subject to updated PPA as described in note 5.
The group's removal and decommissioning liabilities relate mainly to the producing fields.
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 4.14 per cent and 6.35 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 group has not identified any events with significant accounting impacts that have occurred between the end of the reporting period and the date of this report.
The company's investments in licences on the Norwegian Continental Shelf as of:
Skarv 23.835 % 23.835 %
Number 53 53
| Fields operated: | 31.12.2016 | 30.09.2016 Fields non-operated: | 31.12.2016 | 30.09.2016 | |
|---|---|---|---|---|---|
| Alvheim | 65.000 % | 65.000 % Atla | 10.000 % | 10.000 % | |
| Bøyla | 65.000 % | 65.000 % Enoch | 2.000 % | 2.000 % | |
| Hod | 37.500 % | 37.500 % Gina Krog | 3.300 % | 3.300 % | |
| Ivar Aasen Unit | 34.786 % | 34.786 % Johan Sverdrup *** | 11.573 % | 11.573 % | |
| Jette Unit | 70.000 % | 70.000 % Jotun | 7.000 % | 7.000 % | |
| Valhall | 35.953 % | 35.953 % Varg | 5.000 % | 5.000 % | |
| 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 % |
| Production licences in which Aker BP is the operator: | Production licences in which Aker BP is a partner: | ||||
|---|---|---|---|---|---|
| Licence: | 31.12.2016 | 30.09.2016 Licence: | 31.12.2016 | 30.09.2016 | |
| PL 001B | 35.000 % | 35.000 % PL 006C | 15.000 % | 15.000 % | |
| PL 006B | 35.833 % | 35.833 % PL 018DS | 13.338 % | 13.338 % | |
| PL 019 | 80.000 % | 80.000 % PL 019C**** | 30.000 % | 30.000 % | |
| PL 026B** | 90.260 % | 92.130 % PL 026 | 30.000 % | 30.000 % | |
| PL 027D | 100.000 % | 100.000 % PL 029B | 20.000 % | 20.000 % | |
| PL 028B | 35.000 % | 35.000 % PL 035 | 50.000 % | 50.000 % | |
| PL 033 | 37.500 % | 37.500 % PL 035C | 50.000 % | 50.000 % | |
| PL 033B | 37.500 % | 37.500 % PL 038 | 5.000 % | 5.000 % | |
| PL 036C | 65.000 % | 65.000 % PL 038D** | 0.000 % | 30.000 % | |
| PL 036D | 46.904 % | 46.904 % PL 048D | 10.000 % | 10.000 % | |
| PL 065 | 55.000 % | 55.000 % PL 102C | 10.000 % | 10.000 % | |
| PL 088BS | 65.000 % | 65.000 % PL 102D | 10.000 % | 10.000 % | |
| PL 103B | 70.000 % | 70.000 % PL 102F | 10.000 % | 10.000 % | |
| PL 150 | 65.000 % | 65.000 % PL 102G | 10.000 % | 10.000 % | |
| PL 150B | 65.000 % | 65.000 % PL 265 | 20.000 % | 20.000 % | |
| PL 169C | 50.000 % | 50.000 % PL 272 | 50.000 % | 50.000 % | |
| PL 203 | 65.000 % | 65.000 % PL 405** | 15.000 % | 0.000 % | |
| PL 203B | 65.000 % | 65.000 % PL 457 | 40.000 % | 40.000 % | |
| PL 212 | 30.000 % | 30.000 % PL 457BS | 40.000 % | 40.000 % | |
| PL 212B | 30.000 % | 30.000 % PL 492 | 60.000 % | 60.000 % | |
| PL 212E | 30.000 % | 30.000 % PL 502 | 22.222 % | 22.222 % | |
| PL 242 | 35.000 % | 35.000 % PL 507** | 45.000 % | 25.000 % | |
| PL 261 | 50.000 % | 50.000 % PL 533 | 35.000 % | 35.000 % | |
| PL 262 | 30.000 % | 30.000 % PL 550* | 0.000 % | 10.000 % | |
| PL 300 | 55.000 % | 55.000 % PL 554 | 30.000 % | 30.000 % | |
| PL 340 | 65.000 % | 65.000 % PL 554B | 30.000 % | 30.000 % | |
| PL340BS | 65.000 % | 65.000 % PL 554C | 30.000 % | 30.000 % | |
| PL 364 | 100.000 % | 100.000 % PL 610** | 37.500 % | 0.000 % | |
| PL 407 | 50.000 % | 50.000 % PL 613 | 20.000 % | 20.000 % | |
| PL 442** | 90.260 % | 90.000 % PL 627 | 20.000 % | 20.000 % | |
| PL 460 | 100.000 % | 100.000 % PL 627B | 20.000 % | 20.000 % | |
| PL 504 | 47.593 % | 47.593 % PL 650** | 25.000 % | 0.000 % | |
| PL 539** | 0.000 % | 40.000 % PL 653 | 30.000 % | 30.000 % | |
| PL 626 | 50.000 % | 50.000 % PL 672** | 0.000 % | 25.000 % | |
| PL 659** | 35.000 % | 20.000 % PL 689 | 20.000 % | 20.000 % | |
| PL 677 | 60.000 % | 60.000 % PL 689B | 20.000 % | 20.000 % | |
| PL 690* | 0.000 % | 50.000 % PL 694 | 20.000 % | 20.000 % | |
| PL 701* | 0.000 % | 40.000 % PL 721** | 20.000 % | 0.000 % | |
| PL 715 | 40.000 % | 40.000 % PL 722 | 20.000 % | 20.000 % | |
| PL 719** | 20.000 % | 0.000 % PL 778 | 20.000 % | 20.000 % | |
| PL 724 | 40.000 % | 40.000 % PL 782S | 20.000 % | 20.000 % | |
| PL 724B | 40.000 % | 40.000 % PL 782SB | 20.000 % | 20.000 % | |
| PL 736S | 65.000 % | 65.000 % PL 797 | 25.000 % | 25.000 % | |
| PL 748 | 50.000 % | 50.000 % PL 804 | 30.000 % | 30.000 % | |
| PL 762 | 20.000 % | 20.000 % PL 811** | 20.000 % | 0.000 % | |
| PL 777 | 40.000 % | 40.000 % PL 813 | 3.300 % | 3.300 % | |
| PL 777B | 40.000 % | 40.000 % PL 838** | 30.000 % | 0.000 % | |
| PL 784** | 40.000 % | 0.000 % PL 842 | 30.000 % | 30.000 % | |
| PL 790 | 30.000 % | 30.000 % PL 844 | 20.000 % | 20.000 % | |
| PL 814 | 40.000 % | 40.000 % PL 852 | 40.000 % | 40.000 % | |
| PL 818 | 40.000 % | 40.000 % PL 857 | 20.000 % | 20.000 % | |
| PL 821 | 60.000 % | 60.000 % Number | 48 | 45 | |
| PL 822S | 60.000 % | 60.000 % | |||
| PL 839** | 23.835 % | 0.000 % * Relinquished licences or Aker BP has withdrawn from the licence. | |||
| PL 843 | 40.000 % | 40.000 % | |||
| PL 858 | 40.000 % | 40.000 % ** Acquired/changed through licence transactions or licence splits. |
*** According to a ruling by Ministry of Oil and Energy.
**** Aker BP is operator from 18.01.2017
| 2016 | 2015 | ||||||||
|---|---|---|---|---|---|---|---|---|---|
| (USD 1 000) | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | |
| Total income | 655 624 | 247 993 | 255 665 | 204 848 | 254 634 | 316 393 | 321 850 | 328 924 | |
| Exploration expenses | 44 281 | 30 843 | 36 214 | 36 115 | 18 867 | 18 066 | 24 949 | 14 523 | |
| Production costs | 121 139 | 32 188 | 39 116 | 34 374 | 24 077 | 26 888 | 50 686 | 39 349 | |
| Depreciation | 159 796 | 114 649 | 120 264 | 114 318 | 111 590 | 129 790 | 117 354 | 122 224 | |
| Impairments | 44 627 | 8 429 | -19 644 | 37 964 | 191 939 | 185 756 | - | 52 773 | |
| Other operating expenses | 5 029 | 6 223 | 5 410 | 5 330 | 3 228 | 11 433 | 22 550 | 14 397 | |
| Total operating expenses | 374 872 | 192 333 | 181 360 | 228 101 | 349 701 | 371 932 | 215 539 | 243 266 | |
| Operating profit/loss | 280 752 | 55 660 | 74 305 | -23 253 | -95 067 | -55 539 | 106 311 | 85 658 | |
| Net financial items | -70 572 | -5 107 | -28 951 | 7 620 | -56 138 | -51 205 | -43 136 | -4 492 | |
| Profit/loss before taxes | 210 180 | 50 553 | 45 353 | -15 633 | -151 205 | -106 744 | 63 175 | 81 166 | |
| Taxes (+)/tax income (-) | 277 183 | -12 880 | 39 046 | -47 866 | 4 980 | 59 441 | 55 897 | 78 727 | |
| Net profit/loss | -67 003 | 63 433 | 6 308 | 32 233 | -156 184 | -166 185 | 7 277 | 2 439 |
Aker BP discloses 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
Earnings per share (EPS) is net profit divided by weighted average number of shares outstanding and fully diluted
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
Equity ratio is total equity divided by total assets
Gross interest-bearing debt is book value of current and non-current interest-bearing debt
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
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