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E ype_gradient_BLUE_CMYK /2015

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Annual report 2015


Year 2015 Contents

03

08

09

10

11

22

Board of Directors’ Report 2015

Cash flow statement

Income statement

Notes

Balance sheet

Auditor’s report


Year 2015 Board of Directors’ report

Board of Directors’ Report 2015 ENGIE E&P Norge AS (“the Company”) is engaged in the exploration for and production of oil and gas on the Norwegian Continental Shelf (NCS). The Company’s head office is located in Sandnes. At the end of 2015 the Company portfolio contained 46 licences on the NCS, including shares in the Njord, Fram, Snøhvit, Gjøa, Vega, Gudrun, Hyme and H-North fields. The Company is the operator of the Gjøa field (PL153 and PL153B) which started producing in November 2010, and of the exploration licences PL610 Kimbe, PL612 Nemo, PL636 Cara, PL722, PL723 and PL786.

Exploration In January 2016, the Company was awarded a 50% share and the operatorship in a new licence by the Ministry of Petroleum and Energy in the Awards for Predefined Areas (APA) 2015. The licence awarded is PL817 in the North Sea, west of the Gudrun field.

Drilling The Company participated in 2 exploration wells as partner in 2015: PL348C – Bister well 6407/8-7 In Q2 2015, the Company participated in the drilling of exploration well 6407/8-7. The Bister prospect was located 4 km northeast of the Snilehorn discovery and 18 km northeast of the Njord Field. Drilling operations were carried out by the Aker Spitsbergen drilling rig. The exploration target for the well was to prove hydrocarbons in known Jurassic Ile, Tilje and Åre formations. The well encountered reservoir sands in all three reservoir targets, with no signs of hydrocarbons. A side-track was drilled encountering the Tilje and Åre formations, containing no hydrocarbons. Both wells were classified as dry. PL700B – Lorry/Broker well 6407/10-4 In Q4 2015, the Company participated in the drilling of exploration well 6407/10-4, which continued until January 2016. The Lorry prospect was located 15 km southwest

of the Njord Field. Drilling operations were carried out by the Island Innovator drilling rig. The exploration target for the well was to prove hydrocarbons in Upper Jurassic Røgn formation sands. A secondary target was Permian carbonates. The well failed to encounter either of the reservoir targets. Instead, the well encountered a very thick package of what is believed to be Triassic and possibly Permian conglomerates. Hydrocarbon shows were observed in the upper-most layers as seen on core. The well was classified as dry, with minor hydrocarbon shows.

Development Njord Future Project The Njord Future Project is established to decide the optimum future development of the Njord Area and to address the further structural upgrade requirements on the platform. This redevelopment project encompasses the Njord field and the Hyme field which is tied into Njord A. Additional studies have been undertaken for tying-in other discoveries in the area, such as Snilehorn. Sanction of the project is planned to be in November 2016. Snilehorn Development Project The Snilehorn discovery is located approximately 15 km North-East of the Njord Field in the Norwegian Sea. The discovery was made in late 2013 and is most likely to be developed as a tie in to Njord A.

03


Year 2015 Board of Directors’ report

Operations Gjøa Net production from the Gjøa field in 2015 was 12.6 million barrels of oil equivalent (boe) corresponding to 34,413 boe/ day. This represents 36% of the Company’s total production. Production from the Gjøa field has increased compared to 2014, due to excellent regularity and utilisation of Vega spare capacity. Njord Net production from the Njord field in 2015 was 4.5 million boe corresponding to 12,193 boe/day. The field is expected to remain on production until May 2016, before the production platform is towed to shore for the structural upgrade. During this time, no drilling activities will be undertaken. Fram Net production from the Fram field in 2015 was 2.1 million boe corresponding to 5,860 boe/day. The performance of the Fram reservoir has been good and the decline rate is as expected. Fram C-East development was sanctioned Q4 2015. Snøhvit Net production from the Snøhvit field in 2015 was 5.8 million boe corresponding to 15,862 boe/day. 2015 was a strong performing year for Snøhvit with a total regularity of 93% and an average design capacity of 102.5%. The Snøhvit infill well F-1H and the Snøhvit Nord development were sanctioned. The Company lifted 8 LNG cargoes in 2015. Vega Unit Net production from the Vega Unit in 2015 was 0.6 million boe corresponding to 1,621 boe/day. Vega is a subsea tie-back to Gjøa. Hyme Net production from the Hyme field in 2015 was 1.3 million boe corresponding to 3,692 boe/day. The Hyme field is a subsea tie-back to Njord, with one production well and one water injection well. Production will be shut down during the redevelopment of the Njord platform. Gudrun Net production from the Gudrun field in 2015 was 8 million boe corresponding to 21,803 boe/day. The development drilling program (7 production wells) was completed in September 2015. Regularity was affected by a condensate leak in February and helideck integrity issues in March. The West Epsilon drilling rig has been used as helideck for Gudrun since, with the repair of the helideck expected to be completed in April 2016. Despite the leak incident, which caused some 45 days of lost production, regularity for the rest of the year was good, resulting in an average 80% uptime for the year.

H-North Net production from the H-North field in 2015 was 0.2 million boe corresponding to 529 boe/day. Production has been stable from H-North, although at a lower level than expected as one branch of the two-branch producer well has been shut in.

Going concern In accordance with the Accounting Act § 3-3a, the Board of Directors confirms that the financial statements have been prepared under the assumption of going concern. This assumption is based on profit forecasts for the year 2016 and the Company’s long-term strategic forecasts. For the purposes of this rule, the Company’s economic and financial position is sound.

Working environment At year end the Company had 284 employees. In accordance with applicable laws and regulations the Company registers its employees’ absence due to illness. During 2015 absence due to illness has been 1.78% (2.15% in 2014). The Company conducts a periodic working environment survey that includes all employees and consultants. The survey covers a wide range of factors impacting the working environment. The results from the survey form the basis for an annual update of activity plans aimed at maintaining a good working environment. The results from the last survey show that the working environment and general welfare in the workplace is very good. The survey had very high participation at 94% of employees. Over the years, the results have been very good and stable, and any changes this year have been minor. Compared to the Oil and Gas Industry benchmarks, our employee satisfaction is above average. In 2015 the Company had no serious incidents. There were 2 minor injuries, one of them led to a lost time incident (LTI).

Gender equality The Board of Directors is attentive to society’s expectations and the legal requirements with which the Company is expected to comply in order to promote gender equality and prevent differential treatment of women and men. There is a continuous effort to adhere to these requirements. At the year end, 84 of the Company’s 284 employees were women. The management team consists of 9 persons of whom 2 are women. Three of nine members of the Board of Directors are women. A total of 17 new employees were recruited in 2015, of which 5 are women and 12 men. All salaries are established without prejudice. A total of 5 employees work part-time, of which 2 are men. There are no differences in the working hour regulations for women and men.



04


Year 2015 Board of Directors’ report

Discrimination

Financial market, credit and liquidity risks

The Discrimination Act’s objective is to promote gender equality, ensure equal opportunities and rights, and to prevent discrimination due to ethnicity, national origin, descent, skin color, language, religion and faith. The Company is working actively, with determination and systematics to promote the act’s purpose within its business. Included in the activities are recruiting, salary and working conditions, promotion, development opportunities and protection against harassment. The Company aims to be a workplace with no discrimination due to reduced functional ability and is working actively to design and implement the physical conditions in such a manner that as many as possible may utilize the various functions within the workplace. Individual adjustments of workplace and responsibility are made for employees or new applicants with reduced functional ability.

As of 31 December 2015, current and other long-term liabilities amounted to NOK 6,330 million and NOK 10,219 million respectively.

Environment

The Company regards its credit risk as low since the majority of its sales are to companies within the larger ENGIE group and/or to other large corporations. The Company has not realised losses on receivables during the preceding years.

Gjøa field The Gjøa facilities are designed to cause as little environmental impact as possible. Electricity from shore is the main source of power for the Gjøa installation, and there is a single fuel low Nitrous Oxide (NOx) turbine operating the gas export compressor. In addition, a waste heat recovery unit is installed. Closed flaring during regular operations also contributes to a reduction of environmental impact. The emissions and discharges to the environment from operations at Gjøa will be reported to the environmental authorities according to current regulations. 91% of chemicals discharged to sea were green chemicals and are not expected to cause any environmental impact. The company emphasises the use of environmentally friendly chemicals. There was a discharge of yellow chemicals of 140 tons, which exceeded the existing permit (110 tonnes per year), and an update of the permit has therefore been submitted to the Norwegian Environment Agency. In addition, the submitted application provides for the discharge of red and black chemicals related to the leakage of lubricating oil from the submerged electrical pumps and the reclassification of a flocculent from yellow to red category. There were two accidental spills to sea during 2015, both were spills of the green chemical MEG. The Gjøa field generated 84 tons of normal waste and 3,111 tons of hazardous waste in 2015. The key environmental indicators of emissions to air were: Flaring Fuel gas consumption Diesel consumption CO2 emissions NOx emissions

0.3 million standard cubic meters (Sm3) 54 million Sm3 124 tons 125,766 tons 70 tons

The financial position of the Company is good. The financial situation will always be influenced by fluctuations in the price of crude oil and gas and in currency exchange rates. The Company has reimbursed its long term loan. The Company has guidelines for entering into derivative contracts in order to manage the commodity price risk. The Company enters into commodity based derivative contracts consisting of market swaps for oil and gas products to reduce the market exposure. The Company’s financial position means that it would be able to withstand reduced oil prices and fluctuations in exchange rates for an extended period.

The total exposure related to currency, interest and price fluctuations is monitored and evaluated as a part of the overall evaluation of ENGIE’s total exposure. Possible actions are implemented in accordance with existing ENGIE procedures. The pre-tax rate of return (operating profit/average total assets) in 2015 was 23 per cent, compared with 22 per cent in 2014. The rate of return after tax was 9 per cent in 2015, compared with 5 per cent in 2014. The differences between pre-tax income and cash flow from operations are due to differences in the timing of tax expenditures and depreciation.

Financial aspects The Company produced 35.0 million boe in 2015, which is an increase compared to the 2014 level. Total sales in 2015 amounted to 34.4 million boe, giving total revenues of NOK 11,890 million. Out of the total 34.4 million boe sold, 11.2 million barrels (bbls) consisted of crude oil and condensate. Revenues from crude oil and condensate sales were NOK 4,595 million compared to NOK 5,298 million in 2014. The Company sold 2.7 billion Sm3 of gas including Snøhvit LNG in 2015. Revenues from gas and LNG amounted to NOK 5,228 million compared to NOK 4,349 million in 2014. The revenue from sale of Natural Gas Liquid (NGL) and Liquified Petroleum Gas (LPG) mix amounted to NOK 1,318 million in 2015 compared to NOK 1,590 million

05


Year 2015 Board of Directors’ report

in 2014. A total of 5.4 million boe of these products were sold in 2015, compared to 4.4 million boe sold in 2014. Net cash flow from operating activities in 2015 was NOK 5,884 million, compared to NOK 3,827 million in 2014. Capital investments in 2015 amounted to NOK 711 million, compared to NOK 1,243 million in 2014. The majority of the investments were made in the completion of the Gudrun facility along with operating investments on Njord and Snøhvit. The Company’s inter-company debt with ENGIE at the end of 2015 had been fully reimbursed, compared to a balance of NOK 4,067 million at the end of 2014.

of significance that could impact the Company’s result and financial position as at 31 December 2015 which have not been reflected in these accounts. The Company’s fully owned subsidiary, GDF SUEZ E&P Greenland AS, had no revenues in 2015 and incurred costs of NOK 14 million. The Company provided a group contribution to the subsidiary equal to NOK 5.2 million. The Company impaired NOK 18 million of its investment in the subsidiary in 2015. The value of shares in GDF SUEZ E&P Greenland AS as of 31st December 2015 was NOK 53 million.

Allocation of net income

The Company’s net income for 2015 was NOK 457 million higher than 2014. The ordinary pre-tax profit for 2015 was NOK 4,426 million, compared to NOK 5,234 million in 2014. After NOK 4,620 million for current tax expenditures and NOK 1,768 million for deferred tax income, net income amounted to NOK 1,574 million for 2015 compared to NOK 1,117 million in 2014. The accounts have been prepared on a going concern basis. The Board of Directors confirms the basis for this in accordance with section 3-3 of the Norwegian Accounting Act. The Board of Directors is not aware of any conditions

The Board of Directors, having no knowledge of any matters not disclosed that could be of significance when evaluating the Company’s position, recommends the following allocation of net income: Net result 2015 From Retained Earnings Dividend

NOK 1,574,837,110 NOK 759,912,890 NOK 2,334,750,000

If the General Assembly follows the Board of Directors’ recommendation regarding distribution of dividend, total equity after allocation of dividend will be NOK 1,971 million, giving an equity ratio of 10.6%.

8th of March 2016

Maria Moræus Hanssen Chairman of the Board

Didier Holleaux Board Member

Meriem Mokrani Board Member

Rolf Erik Rolfsen Board Member

Benoit Mignard Board Member

Pierre Chareyre Board Member

Mailin Seldal Board Member Employees’ Representative

Trond Myklebust Board Member Employees’ Representative

Arne Bekkeheien Board Member Employees’ Representative

Cedric Osterrieth Managing Director

06


07


Year 2015 Annual accounts

Income statement Note

2015

2014

3, 5

11 742 503 726

11 412 339 733

OPERATING INCOME Sales of oil and gas Tariff income

5

87 959 375

99 405 127

Other Income

5

59 322 543

0

11 889 785 644

11 511 744 859

2 094 393 390

2 057 616 484

Total operating income OPERATING EXPENSES Operating expenses Exploration expenses

378 018 250

626 319 858

6,7

119 960 683

114 688 980

Depreciation

9

3 901 621 355

2 980 153 293

Impairment

9

978 612 961

471 037 054

10

233 422 303

157 004 904

Total operating expenses

7 706 028 941

6 406 820 574

Operating profit

4 183 756 703

5 104 924 285

595 624

943 998

1 105 158 258

1 248 898 481

13 042 000

7 011 812

Payroll expenses

Other operating expenses

FINANCIAL INCOME AND EXPENSES Interest income Foreign currency exchange gain Interest income from group companies Other financial income

11 3

Foreign currency exchange loss Interest expenses to group companies

11

Other interest expenses Net financial (-income) Operating profit before tax Tax expenses

13

Net income

33 280 385

0

847 176 633

1 000 103 738

57 356 000

114 250 046

4 951 701

13 275 238

-242 591 932

-129 225 271

4 426 348 634

5 234 149 556

2 851 511 523

4 116 383 218

1 574 837 110

1 117 766 338

2 334 750 000

1 337 175 000

-759 912 890

-219 408 662

1 574 837 110

1 117 766 338

Allocated as follows: Proposed dividend Transfer (-from) other equity Total allocations

08

14


Year 2015 Annual accounts

Balance sheet NON-CURRENT ASSETS Tangible fixed assets Property, plant & equipment Shares in subsidiary Other financial investments Total non-current assets CURRENT ASSETS Drilling equipment and spare parts

Receivables Accounts receivable from operators Trade accounts receivable Financial instruments Other receivables Total receivables Cash and cash equivalents Total current assets

Note

2015

2014

9

16 006 355 556

20 276 997 749

16

52 974 356

67 567 700

12

Retained earnings Other equity Total equity LIABILITIES Provisions Pension liability Deferred tax Other provisions Total provisions

Current liabilities Loan from parent company Trade accounts payable Public duties payable Accounts payable to operator Dividend Tax payable Other short term liabilities Total current liabilities Total liabilities Total equity and liabilities

188 000

16 059 517 912

20 344 753 449

44 239 473

67 340 200

164 207 824

0

32 168 822

872 461 859

3

954 531 000

445 756 000

11

1 243 797 384

1 839 825 738

2 394 705 031

3 158 043 597

4

Total assets EQUITY AND LIABILITIES EQUITY Paid-in capital Share capital Share premium reserve Total paid-in capital

188 000

22 189 992

254 178 311

2 461 134 496

3 479 562 108

18 520 652 408

23 824 315 557

14,15

141 500 000

141 500 000

14

1 273 500 000

1 273 500 000

1 415 000 000

1 415 000 000

3,14

556 387 986

957 961 366

1 971 387 986

2 372 961 366

7

130 894 114

192 250 109

13

6 114 675 461

7 733 145 594

10

11

3 973 617 374

4 180 150 339

10 219 186 949

12 105 546 043

0

4 067 000 000

83 094 811

164 384 783

49 321 745

137 996 827

307 800 105

886 820 543

14

2 334 750 000

1 337 175 000

13

2 310 620 526

2 039 244 794

8,10

1 244 490 286

713 186 201

6 330 077 473

9 345 808 148

16 549 264 422

21 451 354 191

18 520 652 408

23 824 315 557

09


Year 2015 Annual accounts

Cash flow statement 2015

Operating profit before tax Payment of tax Depreciation, impairments and changes in net present value Changes in accounts receivable and accounts receivable operators Changes in accounts payable and accounts payable operators

4 426 348 634

5 234 149 556

-4 346 595 916

-4 665 262 892

4 910 135 871

3 556 098 817

676 085 213

-643 784 697

-660 310 409

-107 376 034

Difference between pension cost and amounts paid into pension scheme

-32 948 434

17 816 637

Changes in other balance sheet items

911 033 995

435 211 048

5 883 748 953

3 826 852 436

-726 155 617

-1 607 371 378

Net cash flow from operating activities Acquired tangible fixed assets Shares in subsidiary

14 593 345

363 471 739

-711 562 272

-1 243 899 638

Payment of long-term borrowings

-4 067 000 000

-1 000 000 000

Dividend paid

-1 337 175 000

-1 698 000 000

Net cash flow from financing activities

-5 404 175 000

-2 698 000 000

-231 988 319

-115 047 202

254 178 311

369 225 513

22 189 992

254 178 310

Net cash flow from investing activities

Net change in cash and cash equivalents Cash and cash equivalents at beginning of year Cash and cash equivalents at end of year

10

2014


Year 2015 Notes

Notes 01. Accounting policies The annual accounts have been prepared in accordance with the Norwegian Accounting Act of 1998 and Norwegian generally accepted accounting principles.

Exploration costs production asset’s consumption of benefits Geological studies and analysis are over its useful life. expensed as incurred. Exploration drilling costs are temporarily capitalised until Property, plant and equipment is potential oil and gas reserves have been capitalised and depreciated linearly Revenues evaluated (the successful efforts method). over its estimated useful life. Costs for The sale of crude oil and gas is recognised When new reserves are discovered, maintenance are expensed as incurred, through the sales method. For crude oil the fully developed and put into production, whereas costs for improving and upgrading point of delivery is at the offshore loading the exploration drilling costs will be property, plant and equipment are added point or at shipment from the terminal. depreciated based on the unit-of-sales to the acquisition cost and depreciated The point of delivery for gas is at the gas method. Drilling costs related to dry or with the related asset. receiving terminal onshore. non-commercial wells are expensed. Subsidiaries and investment in associates Expenses Property, plant and equipment Subsidiaries and investments in associates Expenses are expensed as incurred in All costs related to the development of are valued at cost in the Company accounts. accordance with the matching principle, commercial oil or gas fields are capitalised The investment is valued as the cost of either along with the revenues they have as a part of the installation. Capital the shares in the subsidiary, less any generated or identified as a periodical expenditures on fields in production impairment losses. Consolidated financial expense. are capitalised based on information statements are not prepared as the from the operator. Company and its subsidiaries are included Estimates in the consolidated financial statements In accordance with Norwegian generally Individual assets or groups of assets, clasof the parent company in France. accepted accounting principles, the sified as cash-generating units (CGUs), are management of the company is responsible tested for impairment when indicators of Assets liabilities and expenses related for estimates and assumptions that affect impairment are identified. When assessing to participating interests in exploration the valuation of assets and liabilities in whether an asset is impaired, the asset's and production licences (joint ventures) the balance sheet and depreciation in the carrying value is compared to the recoThe Company’s participating interests in income statement. The final realisable verable amount. The recoverable amount exploration and production licences on the values may deviate from these estimates. is the higher of the asset's fair value less Norwegian Continental Shelf are accounted cost to sell and the asset's value in use. for in the income statement and balance Classification and assessment of items An impairment loss is recognised when the sheet in accordance with the proportional in the balance sheet recoverable amount is below the carrying consolidation method. Current assets and current liabilities amount and if the decline in recoverable include items due within one year and amount is not considered temporary. If the Transfer of joint ventures shares items related to ordinary working capital. assets are decided to be impaired, the Transfers of interests in petroleum licences All other items are classified as fixed carrying amount is written down to the on The Norwegian Continental Shelf assets or long-term liabilities. recoverable amount and the reduction in require approval from the Norwegian asset value is recognised as an expense. Government. Under such transactions the Current assets are valued at the lower sale price is generally considered to be on of cost and fair value. Short-term debt Depreciation of production assets an "after tax" basis (after-tax transaction) is valued at the historical nominal value. The depreciation of producing assets, as the consideration is not taxable for the including site rehabilitation costs, commen- seller and not deductable for the buyer Fixed assets are valued at cost, but written ces when the oil or gas field is brought into through depreciation. down to fair value if the decline in value is production. Depreciation is calculated not expected to be temporary. Long-term according to the unit of sales method. When acquiring licences that yield rights to loans are stated at the historical nominal According to this method, the depletion exploration for and production of oil and value. rate is equal (since 1 January 2014) to gas, it will be assessed if the acquisition the ratio of oil and gas sales for the period should be classified as a business Foreign currency to proved and probable reserves. Before combination or an asset acquisition. Monetary balance sheet items in foreign this date, the ratio was based on proved Acquisitions of individual licences which currency are converted at the exchange developed reserves. The future capex do not meet the definition of business rate on the closing balance date. linked to the 2P reserves are included combination will be classified as the in the calculation of the depreciation rate. acquisition of an individual asset. All foreign currency transactions are converted to NOK in accordance with the This change of estimate has been decided Oil and gas producing licences Company’s monthly book-keeping currency in view of the evolution of the Group’s For oil and gas producing ownership interexchange rates, which approximate market portfolio of production assets. This change ests, as well as licences in the development rates. aims to improve the economic vision of the phase, the acquisition cost will be allocated

11


Year 2015 Notes

between exploration costs, licence rights, production facilities and deferred taxes. In connection with agreements for acquisitions or trade of interests, the parties will establish a completion date for the acquisition of the net cash flow since the effective date (often set on 1 January of the calendar year). In the period between the effective date and the completion date, the seller will include the acquired interest in the seller’s accounts. In accordance with the acquisition agreement, there will be a settlement with the seller of net cash flow from the ownership interest during the period from the effective date to implementation date (Pro&Contra settlement). The Pro&Contra settlement will be adjusted against the income statement and against the acquisition cost, as the settlement (after reduction for taxes) is regarded as part of the payment for the transaction. Going forward from the implementation date, revenue and costs are included in the buyer’s financial statements. As regards taxes, the buyer will include for taxation net cash flow (Pro&Contra) and any other revenue and costs as of the effective date. Allocations will not be made for deferred taxes in connection with acquisition of licences that are defined as acquisition of assets. Farm-in agreements Farm-in agreements are usually made during the exploration and development phases, and are characterised by the seller deferring future financial advantages, in the form of reserves, to reduce future financing obligations. One example can be that a licence interest is acquired and covered by the seller’s share of the drillingrelated costs. During the exploration phase, the company will normally enter farm-in agreements based on historical costs, as actual value often is difficult to determine. However, during the development phase, farm-in agreements are entered as acquisitions at actual cost when the company is selling shares of oil and gas interests. Fair value is determined by the costs that the buyer has agreed to carry. Swap/Unitisation A swap of ownership interest is measured at the fair value of the interest to be swapped, unless the transaction lacks commercial substance or if the fair value of the swapped interest is not measurable. During the exploration phase where it is often difficult to determine fair value, the Company will normally account for swaps based on historical cost.

12

Spare parts and drilling equipment Spare parts and drilling equipment are valued at the lower of cost or market value. Cost is estimated using the First In First Out (FIFO) method. Capital spare parts are capitalised and presented in the financial statements together with the investment. Over/under lift and petroleum in stock Obligations arising as a result of lifted quantities of crude oil that are larger than the Company’s participating interests in a licence are valued at production cost. Receivables arising as a result of lifted quantities of crude oil that are less than the Company’s share in a licence, are valued at the lower of production cost and sales price. Petroleum in stock which has not passed the Norm Price-point, is valued at production cost, less depreciation.

in pension schemes are amortised over the remaining vesting period. Estimated deviations are continuously charged to equity. Social security tax is included in the pension cost and liability. Accounting for licence cost The Company's accounts reflects the net cost after charging partners their share of licence costs for permits the Company operates. Cash flow statement The cash flow statement is presented using the indirect method. Cash and cash equivalents include bank deposits.

Leasing The Company has signed only operating lease agreements, and as such the related cost is charged to the income statement Uncertain obligations as incurred. The Company will, through its activities, be involved in conflicts and disputes. Financial Instruments The Company will accrue for obligations The Company enters into commodity based in connection with such unresolved issues derivative contracts consisting of market based on the best estimate, when it is pro- swaps for oil and gas products. bable that an outflow of economic benefits will be required to settle the obligation. Hedging The Company applies the principals of Accounts receivables NRS18 and uses the following criteria for Trade accounts receivables and other classifying a derivative or another financial receivables are recorded at face value less instrument as a hedging instrument: (1) the a provision for any anticipated losses. hedging instrument is expected to be highly effective in offsetting changes in Asset retirement obligation the fair value of the cash flow of an identiWhen the retirement obligation is incurred, fied object – the hedging effectiveness is the liability is recognised as a long term expected to be between 80-125%, (2) the provision and the corresponding amount is hedging effectiveness can be measured capitalised as part of the producing asset. reliably, (3) satisfactory documentation is The asset is expensed through depreciation established before entering into the hedging over the remaining useful life of the asset. instrument, showing among other things Future changes in asset retirement that the hedging relationship is effective, obligation estimates are capitalised as (4) for cash flow hedges, that the future part of the asset and charged to profit transaction is considered to be highly and loss prospectively over the remaining probable, and (5) the hedging relationship useful life of the asset. is evaluated regularly with quantitative analysis and is considered to be effective. Tax expense Tax expense reflects both taxes on current Cash flow hedges taxable income and changes in deferred The efficient part of changes in the fair income taxes. Deferred tax is calculated value of a hedging instrument is recognised based on net temporary differences in equity. The inefficient part of the hedging between the book and tax values at year instrument is reported in the income stateend. The calculation has taken into account ment. When a hedging instrument has tax losses carried carry forward and uplift matured, or is sold, exercised or terminated, on capitalised expenditures. or the ENGIE Group discontinues the hedging relationship, even though the Uplift on capitalised expenditures reduces hedged transaction is still expected to the special petroleum tax. Earned uplift occur, the accumulated gains and losses from capitalised expenditures has been at this point will remain in comprehensive fully reflected in the deferred tax income, and will be recognised in the calculation. income statement when the transaction occurs. If the hedged trans-action is no Pensions longer expected to occur, the accumulated Accounting for pensions is based on a unrealised gains or losses on the hedging linear vested principle and on expected instrument will be recognised in the salaries at the point of retirement. Changes income statement immediately.


Year 2015 Notes

02. Financial market risk The Company’s financial result is affected by fluctuations in crude oil and gas prices and foreign currency exchange rates (mainly USD, GBP and EUR). The Company’s loans are stated in NOK and are subject to floating interest rates. Consequently, the Company will be affected also by changes in the interest rate market.

03. Financial Instruments The Company enters into commodity based derivative contracts consisting of market swaps for oil and gas products. Swap contracts for oil are hedged towards Brent Blend; swap contracts for gas are hedged towards National Balancing Point (NBP) and Title Transfer Facility (TTF) prices. The realised value on swap contracts for the year 2015 is a gain of NOK 665 607 697. The realised gain or loss is booked in revenue and financial income/expense where 95% is recognised in revenue and 5% is recognised in financial income/expense. NOK

2015

2014

Total Gas hedging revenue (-loss)

391 937 531

179 728 306

Total Liquids hedging revenue (-loss)

240 389 781

-4 209 160

Total hedging revenues (-loss)

632 329 327

175 519 146

Financial Income from hedging Total hedging income (-loss)

33 280 385

0

665 609 712

175 519 146

The below table shows an overview of the Market to Market (MtM) Asset value as at 31.12.2015, totalling NOK 954 530 292. NOK Cash flow hedge commodities assets Cash flow hedge commodities reserves equity MtM inefficient portion

Booked

31.12.2015

Due

2016

2017

2018

Asset

954 531 000

632 259 109

280 079 279

42 192 612

Equity

680 103 338

450 484 445

199 556 634

30 062 258

Accumulated gain

47 727 000

31 613 242

14 004 106

2 109 652

04. Bank deposits Restricted funds relating to withholding taxes

31.12.15

31.12.14

-

19 491 505

2015 TOTAL

2014 TOTAL

NOK amount During 2015, the Company has issued a bank guarantee towards the tax authorities of 25 000 000 NOK, replacing the cash deposit for withholding taxes.

05. Operating revenues Sales of the Company’s production has derived the following revenues: NOK Crude oil

Norway

UK

Germany

4 360 459 732

4 897 896 084 1 589 785 067

5 227 661 136

4 348 714 305

187 353 118

187 353 118

400 425 129

87 959 375

87 959 375

99 405 127

632 327 312

175 519 146

59 322 543

0

11 889 785 644

11 511 744 858

Gas

496 314 635

Condensate

1 661 844 883 36 438 555

777 361 526 1 317 841 858

Hedging of oil and gas

Total

Netherlands

1 334 702 427

520 902 347

Other income

France

2 698 614 849

NGL

Gas infrastructure

Italy

3 009 252 861

404 251 782

632 327 312 59 322 543

4 050 466 867

36 438 555

1 950 169 170

1 661 844 883

3 786 614 387

404 251 782

13


Year 2015 Notes

06. Salaries and fees NOK Salaries

2015

2014

344 183 546

337 484 906

Social security tax

59 113 770

53 538 296

Pension costs

30 613 542

59 501 185

Other employee benefits

51 130 418

48 151 244

Total salary

485 041 276

498 675 631

Salaries recharged to licences *

365 080 594

383 986 651

Total net salary

119 960 683

114 688 980

281.4

270.7

Number of full-time equivalent employees in fiscal year

* The recharged salary for 2014 has been adjusted compared to previous year's financial statement, to only include recharged salary to operated licences and 3rd parties.

Remuneration for Managing Director The Managing Director position has been shared between Maria Moræus Hanssen and Cedric Osterrieth in 2015. The total salary, bonus and other fringe benefits paid to the Managing Directors are NOK 5 596 448, of which NOK 4 643 980 is salary and NOK 952 468 is other benefits. Remuneration of the Board Payments of remuneration to the Board for the year 2015 totalled NOK 90 000. Share options The General assembly of ENGIE SA has elected to issue restricted share plans and share subscription option plans. The restricted plan is subject to certain conditions, such as remaining in the Company for a certain period. Some employees of the Company were invited to participate in the plans. These plans have no material impact on the financial statements of the Company. Audit fees The fees paid to Ernst & Young during the year 2015 are comprised of the following amounts: NOK

2015

Audit decreed by law

1 233 000

Other attestation services

203 000

Technical VAT and tax services

180 900

Total

1 616 900

07. Pensions The Company is required to have an occupational pension scheme in accordance with the the Norwegian law on required occupational pension ("lov om obligatorisk tjenestepensjon"). The Company's pension scheme meets the requirements of that law. The Company has a retirement benefit plan for all permanent staff. This benefit plan gives the employees the right to receive defined future pensions. The value of these is mainly dependent on the number of years in service and the level of compensation at retirement. The obligation up to 12G is financed through an insurance company, the remainder is financed through normal operation. NOK Pension rights earned during the year Interest expense on earned pension rights Effect of implementation of new pension scheme * Net pension cost

14

2015

2014

64 753 237

54 617 792

4 855 108

4 391 341

-38 994 803

0

30 613 542

59 009 133


Year 2015 Notes

Assets/obligations

2015

Pension benefit obligations Plan assets Change in estimate during the period Effect of implementation of new pension scheme * Net pension liability

2014

369 536 806

272 459 592

-174 627 396

-149 907 304

-25 020 493

69 697 822

-38 994 803

0

130 894 114

192 250 110

Financial assumptions

2015

2014

Discount rate Expected increase in salaries Expected increase in pensions Expected increase of social security base amount (G) Expected return on plan assets

2.50%

2.30%

2.50%

2.75%

0.00%

0.00%

2.25%

2.50%

2.50%

2.30%

* The Company decided to change the pension scheme for the employees from a defined benefit plan to a defined contribution plan, as of 01.01.2016. The new pension scheme will be mandatory for all employees having more than 15 years remaining until retirement age. A reduction of the net pension liability of NOK 38 994 803 has been included in the accounts as of 31.12.2015, to reflect the impact of the change in the pension scheme. This is a best estimate provided by the Company's actuary from Storebrand Pensjonstjenester AS.

08. Related party transactions

Related Party

Company

Value of Transactions 2015

Value of Transactions 2014

Nature of transactions

Other Comments

ENGIE SA

Ultimate parent company

14 083 000

42 649 000

Transportation cost of gas

Income statement

ENGIE SA

Ultimate parent company

1 224 412 000

1 753 141 000

Sales of gas

Income statement

Associated company

26 800 000

18 414 000

Operating and IT expenses

Income statement

ENGIE E&P International SA

Parent company

84 131 000

78 023 000

Operating and support expenses

Income statement

ENGIE E&P International SA

Parent company

13 042 000

7 011 817

Interest & financial income group account

Income statement

GDF SUEZ Trading

Associated company

665 607 697

175 519 146

Settlement of commodities contracts

Income statement

ENGIE CC Division J

Associated company

57 356 000

114 250 046

Interest & financial cost long-term loan

Income statement

GDF SUEZ E&P Greenland AS

Subsidiary

294 462

2 717 348

Salaries and travel expenses

Income statement

GDF SUEZ E&P Greenland AS

Subsidiary

54 366 106

67 474 573

Operating expenses/ Group Contributions

Balance sheet

Parent company

1 337 175 000

1 696 000 000

Dividend paid

Balance sheet

Associated company

15 155 000

6 382 000

Operating and IT expenses

Balance sheet

Ultimate parent company

148 646 000

34 386 000

Accrued gas sales

Balance sheet

Associated company

4 067 000 000

1 000 000 000

Repayment of loan

Balance sheet

Parent company

56 790 000

50 450 000

Cost accruals

Balance sheet

GDF SUEZ Trading

Associated company

943 805 000

222 680 000

Margin call

Balance sheet

GDF SUEZ Trading

Associated company

148 155 000

Accrued settlement commodities contracts

Balance sheet

GDF SUEZ DEXpro

ENGIE E&P International SA GDF SUEZ DEXpro ENGIE SA ENGIE CC Division J ENGIE E&P International SA

15


Year 2015 Notes

09. Tangible fixed assets NOK Acquisition cost at 01.01.2015 Acquisitions during the year Disposal I) II) Impairment during the year III)

Assets in Production

Assets under development

Equipment Capitalised etc. exploration cost

TOTAL

34 980 563 409

41 519 433

509 760 959

402 532 803

591 970 219

45 343 406

29 703 687

68 932 106

34 934 376 603 735 949 418

-5 427 855

0

0

-142 885 844

-148 313 699 -960 241 072

-938 190 000

0

0

-22 051 072

3 512 542

10 592 437

-4 512 542

-9 592 437

0

Acquisition cost at 31.12.2015

34 632 428 315

97 455 275

534 952 104

296 935 557

35 561 771 252

Less accumulated depreciation at 31.12.2015

-19 139 267 677

0

-416 148 018

0

-19 555 415 695

15 493 160 638

97 455 275

118 804 086

296 935 557

16 006 355 557

3 837 225 976

0

64 395 378

0

3 901 621 355

Reclassification

Book value as at 31.12.2015 Current year depreciation Estimated useful life

3-8 years

I) Disposal of capitalised exploration cost mainly represents the sale of a 5% share in the licences PL107B, PL107D and 348C to Core Energy. The consideration was USD 30 000 000. The total asset value in the balance sheet corresponding to the 20% equity share has been booked against the disposal line in the profit & loss. II) Capitalised exploration drilling costs from previous years are evaluated as non-commercial discoveries. III) During the course of the income year 2015, indicators of impairment were identified (such as changes in price levels and changes in recoverable reserves) which triggered an impairment assessment. The impairment assessment for 2015 is based on value in use. The economic assumptions applied for the impairment assessment, such as commodity price trends, reserve estimates, exchange rates and discount rates are determined and approved at ENGIE group level. The discount rate used for determining the value in use as the recoverable amount, is based on the ENGIE group's weighted average cost of capital (WACC). The base discount rate for value in use calculations is 6.5% nominal, after tax. Discount rates used in the impairment assessments reflect the current market assessment of time value of money and risks specific to the liability concerned. Production profiles applied in the calculation are based on estimated proven and probable recoverable reserves and price levels applied in the calculation are based on observable market prices and management's estimates (dated 30.12.2015). Price levels used in value in use calculation for the first 3 years are based on observable market prices for commodities, starting from the valuation date. The projections used for commodity prices beyond the liquidity period are in line with the consensus drawn up on the basis of several external studies.

10. Other provisions and obligations NOK

2015

2014

Asset retirement obligation

3 707 512 476

3 789 682 424

Other long-term provisions

266 104 898

390 467 915

3 973 617 374

4 180 150 339

Other provisions

Other long-term provisions Other long term provisions are the Company's net liability related to the Gjøa liability to the Vega licences. This long term debt relates to capex pre-payments from the Vega licences to the Gjøa development project. The Gjøa liability is reduced according to units of production, based on the throughput of hydrocarbons from the Vega licences in the Gjøa processing facility. Asset retirement obligation In accordance with the concession terms of the Production licences which the Company holds, the Norwegian State can assume ownership of licence installations without charge when the production ends or when the licence expires. Alternatively the State can require the installations to be removed. In addition to provisions for future abandonment cost, provisions have been made for future costs of plugging and securing production wells. The accretion expense is classified as an operating expense.

16


Year 2015 Notes

2015

2014

Asset retirement obligations at January 1

3 789 682 424

3 232 871 087

Liabilities incurred / revision in estimates

-175 886 035

448 972 781

Accretion expense

93 716 087

107 838 556

Asset retirement obligations at December 31

3 707 512 476

3 789 682 424

Long-term assets related to removal and abandonment at January 1

1 943 979 784

1 823 427 165

Additional assets / revision in estimates

-175 886 035

451 902 887

Depreciation

-506 617 621

-331 350 268

1 261 476 128

1 943 979 784

Long-term assets related to removal and abandonment at December 31

Assets related to removal and abandonment are also included within tangible fixed assets described in note 9. Drilling commitments The Company, together with its licence partners, is committed to taking part in the drilling of wells in accordance with its licence agreements. Contractual obligations Obligations committed NOK

2016

Thereafter

Total

1 813 706 000

1 572 618 000

3 386 324 000

The contractual obligations are related to the acquisition and construction of assets in licences where the Company has ownership interests.

11. Inter-company balances Receivables Trade accounts receivable from inter-company Short-term receivables from parent company Interest income Liability Loan Interest expenses Margin Call

31.12.15

31.12.14

296 801 000

275 995 110

3 243 000

170 092 000

13 042 000

7 011 812

31.12.15

31.12.14

-

4 067 000 000

57 356 000

113 327 000

943 805 000

222 680 000

Interest expense on the loans in 2015 totalled NOK 57 356 000, of which none was capitalised. The loan was reimbursed at maturity during 2015.

12. Drilling equipment Spare parts and drilling equipment are valued at the lower of cost or market value. Cost is estimated using the First In First Out (FIFO) method. Capital spare parts are capitalised and presented in the financial statements together with the investment. 2015

2014

Drilling and well equipment

44 239 473

67 340 200

Total Inventories

44 239 473

67 340 200

17


Year 2015 Notes

13. Taxes 2015

2014

-1 738 631 204

-285 176 787

Specification of the tax expense for the year: Change in deferred tax before adjustment in tax rates Deferred tax charge effect from new tax rates, 25% and 53% * Current tax payable Adjustment for tax provision in prior years Total tax expense

-29 855 917

0

4 630 646 633

4 471 879 092

-10 647 989

-70 319 087

2 851 511 523

4 116 383 218

4 426 348 634

5 234 149 557

4 428 931

549 412 299

Specification of the tax basis for the year: Ordinary profit before tax Permanent differences Change in temporary differences

2 416 931 300

598 321 818

Basis ordinary income tax

6 847 708 865

6 381 883 674

Financial expenses not subject to special petroleum tax

-234 050 613

-164 842 002

Income from onshore activities

-674 550 233

-186 494 792

Uplift on capitalised expenditures

-484 666 374

-640 800 802

5 454 441 646

5 389 746 078

Basis special petroleum tax Tax payable: Tax payable - ordinary income tax 27%

1 848 881 394

1 723 108 592

Tax payable - special petroleum tax 51%

2 781 765 239

2 748 770 500

Total tax payable

4 630 646 633

4 471 879 092

11 659 779 070

14 463 484 466

-130 894 114

-192 250 109

Specification of basis for deferred tax: Net differences: Fixed assets Pension liability Crude oil inventory Gain and loss account Hedging Asset Price review Asset retirement obligations Basis ordinary income tax Limited capitalisation of interest on development projects Hedging Asset Unused uplift Basis special petroleum tax

2 381 327

12 318 740

36 422 339

34 434 174

954 712 441

445 936 403

0

-248 503 750

-3 668 737 918

-3 750 907 867

8 853 663 146

10 764 512 057

-81 489 401

-95 049 754

-954 712 441

-445 936 403

-456 593 994

-759 355 723

7 360 867 310

9 464 170 177

Deferred Tax Liability: Ordinary income tax (27%)

2 390 489 049

2 906 418 255

Special petroleum tax (51%)

3 754 042 328

4 826 726 790

Deferred tax liability effect from new tax rates, 25% and 53% Total deferred tax Of which booked against equity

18

-29 855 917

0

6 114 675 461

7 733 145 046

-190 374 110

-72 268 655


Year 2015 Notes

2015

2014

4 630 646 633

4 471 879 092

Tax payable: Ordinary income tax Tax effect of acquisition cost Tax effect of group contribution Prior year adjustments Tax paid in advance Total tax payable in balance sheet

0

-3 859 733

1 401 567

-27 102 331

-2 661 675

-13 622 233

-2 318 766 000

-2 388 050 001

2 310 620 525

2 039 244 794

Reconciliation of tax expense and calculated tax expense Ordinary profit before tax

4 426 348 634

5 234 149 557

Marginal tax at 78%

3 452 551 935

4 082 636 654

-94 045 362

-163 743 100

-339 459 925

-89 514 765

Uplift on capitalised expenditures Hedging Permanent difference §10

122 930 789

95 702 359

Impairment/proceeds on sale

-111 163 054

367 408 902

-7 633 159

-26 471 289

Other permanent differences Financial items not subject to special petroleum tax Adjustments from prior years Effect of changing tax rates to 25% and 53% Tax expense

-131 165 796

-79 316 456

-10 647 989

-70 319 087

-29 855 917

0

2 851 511 523

4 116 383 218

* The corporate tax rate and the special petroleum tax rate will change to 25% and 53% respectively to be effective from income year 2016 (changing from 27% and 51% respectively in 2015).

14. Equity

Equity at 31.12.14

Share capital

Share premium reserve

141 500 000

1 273 500 000

Current year net income Pension actuarial valuation Hedging MTM Dividend 2015 Equity at 31.12.15

141 500 000

1 273 500 000

Other equity

Total

957 961 366

2 372 961 366

1 574 837 111

1 574 837 111

5 504 508

5 504 508

352 835 000

352 835 000

-2 334 750 000

-2 334 750 000

556 387 985

1 971 387 985

15. Share capital and shareholder information The share capital of the Company consists of 141 500 shares with a nominal value of NOK 1 000 per share. All shares are held by the parent company, ENGIE E&P International SA. The parent company (ENGIE E&P International SA, with head-office located in Paris) issues consolidated statements which include ENGIE E&P Norge AS and GDF SUEZ E&P Greenland AS.

19


Year 2015 Notes

16. Investment in subsidiaries Investments in subsidiaries are valued at cost in the accounts of the Company. Company

Business office

Share

Stavanger

100%

GDF SUEZ E&P Greenland AS

In 2015 the Company made a group contribution to the subsidiary of NOK 5 176 089. The Company impaired NOK 18 371 889 of its investment in the subsidiary in 2015.

17. Reserves (not audited) According to the reserves information published by the Norwegian Oil Directorate, the Company`s share of remaining reserves at 31.12.2015 are: NGL (million tonnes)

Condensate (mill Sm3)

3.40

0.96

0.00

1.08

0.09

0.00

0.03

0.00

0.00

0.00

01.10.35

0.00

22.69

0.71

2.46

08.07.28

1.02

5.85

1.56

0.00

0.15

0.45

0.20

0.00

0.52

0.08

0.02

0.00

1.00

0.25

0.00

Licence duration

Oil (mill Sm3)

Gas (bill Sm3)

Njord

10.04.23

1.20

Fram

09.03.24

0.95

Fram H-North

09.03.24

Snøhvit Gjøa Vega

09.03.24

Hyme

17.12.29

Gudrun

31.12.28

1.93

31st of December 2015 / 8th March 2016

Maria Moræus Hanssen Chairman of the Board

Didier Holleaux Board Member

Meriem Mokrani Board Member

Rolf Erik Rolfsen Board Member

Benoit Mignard Board Member

Pierre Chareyre Board Member

Mailin Seldal Board Member Employees’ Representative

Trond Myklebust Board Member Employees’ Representative

Arne Bekkeheien Board Member Employees’ Representative

Cedric Osterrieth Managing Director

20


21


Year 2015 Auditor’s report

Auditor’s report

22


Year 2015 Auditor’s report

23


Foto: Jan Inge Haga

hschild - 92288 Suresnes - FRANCE 0 / Fax : +33 (0)1 57 32 87 87

07

E ype_gradient_WHITE /2015

ENGIE E&P Norge AS Vestre Svanholmen 6, Sandnes. Postboks 242, 4066 Stavanger. T +47 52 03 10 00. post@no-epi.engie.com www.engie-ep.no

RÉFÉRENCES COULEUR

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ENGIE E&P Norge  

Annual report 2015

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Annual report 2015

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