M&A Activity • Dec 1, 2017
M&A Activity
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(a public limited liability company incorporated under the laws of Norway)
The information contained in this information memorandum (the "Information Memorandum") relates to the acquisition of Hess Norge AS ("Hess Norge") (the "Transaction") by Aker BP ASA, a public limited liability company existing under the laws of Norway ("Aker BP" or the "Company", and taken together with its subsidiaries, the "Group").
This Information Memorandum serves as an information document as required under Section 3.5 of the Continuing Obligations for Stock Exchange Listed Companies (the "Continuing Obligations"). The Continuing Obligations apply in respect of companies with shares admitted to trading on Oslo Børs (the "Oslo Stock Exchange") and this Information Memorandum has been submitted to the Oslo Stock Exchange for inspection before it was published. This Information Memorandum is not a prospectus and has neither been inspected nor approved by the Norwegian Financial Supervisory Authority (Nw. Finanstilsynet) in accordance with the rules that apply to prospectuses.
On 24 October 2017, the Company entered into a share purchase agreement (the "SPA") with Hess Norway Investments Limited as seller (the "Seller"), in respect of the Transaction. The Company will acquire 100% of the shares in Hess Norge against a cash consideration.
This Information Memorandum does not constitute an offer or solicitation to buy, subscribe or sell the securities described herein, and no securities are being offered or sold pursuant to this Information Memorandum.
In reviewing this Information Memorandum, you should carefully consider the matters described in Section 1 "Risk Factors" beginning on page 3.
The date of this Information Memorandum is 1 December 2017.
The information contained herein is current as of the date hereof and subject to change, completion and amendment without notice. The publication and distribution of this Information Memorandum shall not under any circumstances create any implication that there has been no change in the affairs of the Group or that the information herein is correct as of any date subsequent to the date of this Information Memorandum. No person is authorised to give information or to make any representation in connection with the Transaction other than as contained in this Information Memorandum. The contents of this Information Memorandum are not to be construed as legal, business or tax advice. Each reader of this Information Memorandum should consult with his or her own legal, business or tax advisor as to legal, business or tax advice. No due diligence has been made on the Company in connection with preparation of this Information Memorandum.
This Information Memorandum includes forward· looking statements that reflect the Company's current views with respect to future events and financial and operational performance, as well as other statements relating to the Group's future business development and economic performance. These forward-looking statements can be identified by the use of forward·looking terminology, including the terms "assumes", "projects", "forecasts", "estimates", "expects", "anticipates", "believes", "plans", "intends", "may", "might", "will", "would", "can", "could", "should" or, in each case, their negative, or other variations or comparable terminology. These forward-looking statements are not historic facts. They appear in a number of places throughout this Information Memorandum and include statements regarding the Company's intentions, beliefs or current expectations concerning, among other things, goals, objectives, financial condition and results of operations, liquidity, prospects, growth, strategies, impact of regulatory initiatives, capital resources, and the industry trends and developments. Readers are cautioned that forward-looking statements are not guarantees of future performance and that the actual financial condition, operating results and liquidity of the Group, and the development of the industries in which it operates, may differ materially from those made in or suggested by the forward-looking statements contained in this Information Memorandum. By their nature, forward-looking statements involve and are subject to known and unknown risks, uncertainties and assumptions as they relate to events and depend on circumstances that mayor may not occur in the future. Because of these known and unknown risks, uncertainties and assumptions, the outcome may differ materially from those set out in the forward-looking statements.
The Company undertakes no obligation to publicly update or publicly revise any forward-looking statement, whether as a result of new information, future events or otherwise. All subsequent written and oral forward-looking statements attributable to the Company or to persons acting on the Company's behalf are expressly qualified in their entirety by the cautionary statements referred to above and contained elsewhere in this Information Memorandum.
This Information Memorandum shall be governed by and construed in accordance with Norwegian law. The courts of Norway, with Oslo as legal venue, shall have exclusive jurisdiction to settle any dispute which may arise out of or in connection with this Information Memorandum.
The information in this Information Memorandum that has been sourced from third parties has been accurately reproduced and as far as the Company is aware and able to ascertain from information published by that third party, no facts have been omitted which would render the reproduced information inaccurate or misleading.
The Continuing Obligations allow the Company to incorporate by reference information in this Information Memorandum that has been previously filed with the Oslo Stock Exchange or the Norwegian Financial Supervisory Authority in other documents. The audited historical consolidated financial statements for the Group as of and for the years ended 31 December 2016, 2015 and 2014 prepared in accordance with International Financial Reporting Standards as adopted by the European Union ("IFRS")(the "Annual Financial Statements"), the unaudited historical condensed interim financial statements for the Group as of and for the nine months ended 30 September 2017 and 2016 prepared in accordance with International Accounting Standard 34 Interim Financial Reporting ("lAS 34") (the "Interim Financial Statements") and the audit reports in respect of the Annual Financial Statements have been incorporated as a part of this Information Memorandum; see Section 11 "Incorporation by Reference; Documents on Display". Accordingly, this Information Memorandum is to be read in conjunction with these documents.
| Clause | Page | |
|---|---|---|
| 1. | RISK FACTORS | 3 |
| 2. | RESPONSIBILITY STATEMENT | 19 |
| 3. | PRESENTATION OF AKER BP ASA | 20 |
| 4. | THE TRANSACTION | 39 |
| 5. | PRESENTATION OF HESS NORGE AS | 41 |
| 6. | THE COMPANY FOLLOWING COMPLETION OF THE TRANSACTION | 43 |
| 7. | INDUSTRY OVERVIEW | 43 |
| 8. | SELECTED FINANCIAL INFORMATION FOR THE GROUP | 55 |
| 9. | PRO FORMA FINANCIAL INFORMATION | 59 |
| 10. | SELECTED FINANCIAL INFORMATION FOR HESS NORGE AS | 71 |
| 11. | INCORPORATION BY REFERENCE; DOCUMENTS ON DISPLAY , |
75 |
| 12. | DEFINITIONS | 77 |
| APPENDIX A- INDEPENDENT PRACTITIONERS ASSURANCE REPORT ON THE COMPILATION OF PRO FORMA | A1 | |
| FINANCIAL INFORMATION INCLUDED IN AN INFORMATION MEMORANDUM |
||
| APPENDIX B - ANNUAL ACCOUNTS OF BP NORGE AS | B1 | |
| APPENDIX C - ANNUAL ACCOUNTS OF HESS NORGE AS | C1 |
Holders of shares in the Company ("Shares") should consider the risks described below, as well as the other information in this Information Memorandum. The order in which the risks are presented below is not intended to provide an indication of the likelihood of their occurrence nor of their severity or significance.
The information contained in this Section 1 "Risk Factors" identifies certain factors that could adversely affect the business, financial condition, operating results, liquidity, performance and prospects of the Group. Readers are urged to read all sections of this Information Memorandum.
The unaudited pro forma financial information included in this Information Memorandum has been prepared solely to show what the significant effects of the Transaction might have been had the Transaction occurred at an earlier date and does not purport to present the results of operations or financial condition of the Group, nor should it be used as the basis of projections of the results of operations or financial condition of the Group for any future period or date.
This Information Memorandum includes unaudited pro forma consolidated financial information for the Group as of and for the year ending 31 December 2016. Although the unaudited pro forma financial information is based on estimates and assumptions based on current circumstances believed to be reasonable, actual results could have materially differed from those presented herein. There is a greater degree of uncertainty associated with pro forma figures than with actual reported results. The unaudited pro forma financial information has been prepared for illustrative purposes only and, because of its nature, addresses a hypothetical situation and, therefore, does not purport to present the results of operations of the Group as if the Transaction had occurred at the commencement of the period being presented, or the financial condition of the Group as of the date being presented, nor should it be used as the basis of projections of the results of operations for the Group for any future period or the financial condition of the Group for any date in the future.
Under the SPA, consummation of the Transaction is conditional upon satisfaction of a number of conditions that are beyond the control of the Company; the Transaction may hence not be consummated and transaction costs wj{{ have been incurred for the Group regardless of whether the Transaction is consummated which could negatively affect the business, results of operation and financial condition of the Group.
Consummation of the Transaction is conditional upon satisfaction of a number of conditions, the satisfaction of which are beyond the control of the Company; see Section 4 "The Transaction". If the Transaction is not consummated, transaction costs, including costs of advisors and the use of key management personnel's time and attention, will have been incurred without the expected benefits and at the expense of other business opportunities.
In addition, there will be no realisation of any of the expected benefits of having completed the Transaction and failure to complete the Transaction could result in a negative perception by the stock market of the Company and result in a decline of the market value of the Company's shares.
If any of the above or below risks materialise, it could negatively affect the business, results of operation and financial condition of the Group.
Some of Hess Norge's contracts contain consent requirements triggered by the Transaction. The Company may not be able to obtain such consents, or may be unable to renew the existing contracts entered into by Hess Norge or establish new contracts on terms as favourable as those contracts currently held. Further, the Company may incur transfer fees under certain contracts as a result of the Transaction.
The Company will acquire the shares in Hess Norge on "as is" terms, with certain limited warranties and indemnities from Hess relating to inter alia ownership and title to the shares and certain other matters. The Company may discover issues or liabilities relating to Hess Norge's business that may have a material adverse effect on the Company's business, results of operations, cash flow and financial condition, which the Company may not be entitled to seek remedy for from the Seller.
By acquiring the shares in Hess Norge on "as is" terms, Aker BP will also assume Hess Norge's tax positions, which include a tax loss carry forward. The timing of the realization of such a tax position is uncertain, as it may depend on the Company's inter alia ability to maintain reliable production from its asset and sufficient operating profit to offset the tax loss carry forward. Furthermore, by acquiring the shares in Hess Norge, Aker BP assume disputed tax positions and the potential of being subjected to claims from the Norwegian tax authorities, including the risk that the tax authorities successfully challenges past deductions or capitalizations with the result that the tax losses carried forward is reduced, which may have an adverse effect on the Company's financial position. The timing and value of the realization of Hess Norge's tax loss carried forward could have an adverse effect on the Company's financial and liquidity position.
The Company will most likely be required to operate its petroleum activities on the Norwegian Continental Shelf in a single legal entity, and intends to acquire the license interests of Hess Norge subsequent to taking over the shares in Hess Norge. A customary condition set by the MPE in scenarios where a single license holder acquires 100% of a license interest, is that a portion of such license interests is divested to a third party either prior to completion of the transaction or within a specified timeframe. There can be no assurances that the Company would be able to achieve terms similar to, or better than, those of the Transaction, or that the Company is successful in getting a license partner that shares the strategic plans of the Company for the further development of the assets, should the Company be required to divest a share of the production licenses included in the Transaction. Should these risks materialize, it could have an adverse effect on the Group's operations, financial condition and results.
The Company's future revenues, cash flow, profitability and rate of growth depend substantially on prevailing international and local prices of oil and gas. Because oil and gas is globally traded, the Company is unable to control the prices it receives for the oil and gas it produces.
Both oil and gas prices are volatile and are subject to significant fluctuations for many reasons, including, but not limited to:
terrorism or the threat of terrorism, war or threat of war, or cyber security attacks, which may affect supply, transportation or demand for hydrocarbons and refined petroleum products.
It is impossible to accurately predict future oil and gas price movements. Historically, crude oil prices have been highly volatile and subject to large fluctuations in response to relatively minor changes in the demand for oil. For example, during 2016, oil prices dipped below approximately USD 30 per barrel and rose to approximately USD 50 per barrel by the end of the year.
The Company's profitability is determined in large part by the difference between the income received from the oil and gas that it produces and its operational costs, taxation, as well as costs incurred in transporting and selling the oil and gas. Therefore, lower prices for oil and gas may reduce the amount of oil and gas that the Company is able to produce economically or may reduce the economic viability of the production levels of specific wells or of projects planned or in development to the extent that production costs exceed anticipated revenue from such production. This may result in the Company having to make substantial downward adjustments to its oil and gas reserves.
The economics of producing from some wells and assets may also result in a reduction in the volumes of its reserves which can be produced commercially, resulting in decreases to its reported commercial reserves. Further reductions in commodity prices may result in a reduction in the volumes of its reported reserves. The Company might also elect not to produce from certain wells at lower prices, or the other license participants may not want to continue production regardless of Aker BP's position. All of these factors could result in a material decrease in its net production revenue, causing a reduction in its oil and gas exploration and development activities and acquisition of reserves. In addition, certain development projects could become unprofitable as a result of a decline in price and could result in the Company having to postpone or cancel a planned project, or if it is not possible to cancel the project, carry out the project with negative economic impact. Further, a reduction in oil prices may lead its producing fields to be shut down and enter into the decommissioning phase earlier than estimated.
In addition, a substantial material decline in prices from historical average prices could reduce its ability to refinance its outstanding credit facilities and could result in a reduced borrowing base under credit facilities available to the company, including the RBL Facility. Changes in the oil and gas prices may thus adversely affect its business, results of operations, cash flow, financial condition and prospects.
Sustained lower oil and gas prices may cause the Company to make substantial downward adjustments to its oil and gas reserves. If this occurs, or if its estimates of production or economic factors change, the Company may be required to write-down, as a non-cash charge to earnings, the carrying value of its proved oil and gas properties for impairments. Accounting rules applicable to the Company require that the Company periodically reviews the book value of its properties and goodwill for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews and the continuing evaluation of development plans, production data, economics and other factors, the Company may be required to write down the carrying value of its oil and natural gas properties or goodwill to the extent that such tests indicate that the carrying value may not be recoverable due to a reduction of the estimated useful life or estimated future cash flows of its oil and natural gas properties. Such write-downs constitute a non-cash charge against current earnings.
Adverse changes to commodity prices could cause the Company to record additional impairments (on top of the additional impairments the Company has accounted for) of its oil and gas properties and goodwill in future periods, which could materially adversely affect its results of operations in the period incurred.
The main part of the goodwill recognized from the Marathon acquisition is, for the purpose of impairment testing, allocated to fields from Marathon Norway. The lifetime of this technical goodwill will be limited by the lifetime of the fields of which it is allocated to. Impairment is thus expected to be charged as the reserves are being produced. When the fields have no more economical reserves, this goodwill will have to be fully impaired. Similarly, the majority of the technical goodwill associated with the BP acquisition also has a limited lifetime and will be subject to the same impairment considerations. Hence, the goodwill should be fully impaired at the time that the related fields have ceased production. The same methodology as described for the Marathon and the BP acquisitions, is expected to be applied for the technical goodwill recognized in the Transaction. According to IFRS, goodwill shall not be subject to depreciation and the decrease in technical goodwill therefore needs to be presented as impairment. Going forward, management therefore expects additional impairment charges of the goodwill recognized in the Marathon acquisition, BP acquisition and the Transaction, which could materially affect its results of operations in the period incurred.
In addition, the depreciation of oil and gas assets charged to its income statement is dependent on the estimate of its oil and gas reserves. An increase in estimated reserves will cause a reduction to its income statement charge because a larger base exists on which to depreciate the asset. Correspondingly, a decrease in estimated reserves will cause an increase to its income statement charge. The estimate of oil and gas reserves also underpins the net present value of a field used for impairment calculations, and reductions to the commercial reserves estimate can lead to an impairment charge.
The Company may be affected by the general state of the economy and business conditions, including but not limited to, the occurrence of recession and inflation, unstable or adverse credit markets, fluctuations in operating expenses, technical problems, work stoppages or other labor difficulties, property or casualty losses which are not adequately covered by insurance, and changes in governmental regulations, such as increased taxation or the introduction of new regulations, increasing operating costs and capital expenditure, which may materially and adversely affect its business, operating results, cash flow and financial conditions. Weak global or regional economic conditions may negatively impact its business in ways that the Company cannot predict. Global financial markets and economic conditions have been severely disrupted and volatile in recent years and remain subject to significant vulnerabilities, such as the deterioration of fiscal balances and the rapid accumulation of public debt, continued deleveraging in the banking sector and a limited supply of credit. As a result of disruptions in the credit markets and higher capital requirements, many lenders have increased margins on lending rates, enacted tighter lending standards, required more restrictive terms (including higher collateral ratios for advances, shorter maturities and smaller loan amounts), or have refused to refinance existing debt at all. Additional tightening of capital requirements, and the resulting policies adopted by lenders, could further reduce lending activities. The Company may experience difficulties obtaining financing commitments or be unable to fully draw on the capacity under committed loans the Company arranges in the future if its lenders are unwilling to extend financing to the Company or unable to meet their funding obligations due to their own liquidity, capital or solvency issues. The Company cannot be certain that financing will be available on acceptable terms or at all. If financing is not available when needed, or is available only on unfavorable terms, the Company may be unable to meet its future obligations as they come due. Our failure to obtain such funds could have a material adverse effect on its business, results of operations and financial condition, as well as its ability to service its indebtedness.
Oil and gas exploration and production activities are capital intensive and inherently uncertain in their outcome. Significant expenditure is required to establish the extent of oil and gas reserves through seismic and other surveys and drilling and there can be no certainty that further commercial quantities of oil and gas will be discovered or acquired by the Company. The Company's existing and future oil and gas appraisal and exploration projects may therefore involve unprofitable efforts, either from dry wells or from wells that are productive but do not produce sufficient net revenues to return a profit after development, operating and other costs. Few prospects that are explored are ultimately developed into producing oil and gas fields. Even if the Company is able to discover or acquire commercial quantities of oil and gas in the future, there can be no assurance that these will be commercially developed.
Completion of a well does not guarantee a profit on the investment or recovery of the costs associated with that well. Additionally, the cost of operations and production from successful wells may be materially adversely affected by unusual or unexpected geological formation pressures, oceanographic conditions, hazardous weather conditions, delays in obtaining governmental approvals or consents, shut-ins of connected wells, difficulties arising from environmental or other challenges or other factors. Any inability on the Company's part to recover its costs and generate profits from its exploration and production activities could have a material adverse effect on its business, results of operations, cash flow and financial condition.
Additionally, production from oil and natural gas reservoirs, particularly in the case of mature fields, is generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The rate of decline will change if production from existing wells declines in a different manner than the Company has estimated and can change under other circumstances. Thus, its future oil and natural gas reserves and production and, therefore, its cash flow and results of operations are highly dependent upon its success in efficiently developing and exploiting its current properties and economically finding or acquiring additional recoverable reserves. The Company may not be able to develop, find or acquire additional reserves to replace its current and future production at acceptable costs. If the Company is unable to replace its current and future production, the value of its reserves will decrease, and its business, financial condition and results of operations would be adversely affected.
Developing oil and gas resources and reserves into commercial production involves a high degree of risk. Our operations are subject to all the risks common in its industry. These hazards and risks include but are not limited to encountering unusual or unexpected rock formations or geological pressures, geological uncertainties, seismic shifts, blowouts, oil spills, uncontrollable flows of oil, gas or well fluids, explosions, fires, improper installation or operation of equipment and equipment damage or failure.
Given the nature of its offshore operations, its exploration, production and drilling facilities are also subject to the hazards inherent in marine operations, such as capsizing, sinking, grounding and damage from severe storms or other severe weather conditions.
The offshore operations conducted by the Company involves risks including but not limited to high pressure drilling, mechanical difficulties, or equipment failure which increase the risk of delays in drilling and of operational challenges arising, as well as material costs and liabilities occurring.
If any of these events were to occur in relation to any of its licenses, they could, among other adverse effects, result in environmental damage, injury to persons and loss of life and a failure to produce oil and/or gas in commercial quantities. They could also result in significant delays to drilling programs, a partial or total shutdown of operations, significant damage to its equipment and equipment owned by third parties and personal injury or wrongful death claims being brought against the Company. These events can also put at risk some or all of its licenses and could result in the Company incurring significant civil liability claims (as BP incurred following the Macondo well blowout), significant fines or penalties as well as criminal sanctions potentially being enforced against Aker BP and/or its officers. The Company may also be required to curtail or cancel any operations on the occurrence of such events.
In its capacity as holder and operator of licenses under the Norwegian Petroleum Act, the Company is subject to strict statutory liability in respect of losses or damage suffered as a result of pollution caused by spills or discharges of petroleum from facilities or otherwise resulting from its petroleum activities on the NCS. The statutory regulations set out that anyone who suffers damage or loss as a result of pollution caused by any of the license areas can claim compensation from the Company without needing to demonstrate that the damage is due to any fault on its part. Furthermore, the statutory regulations also restrict the right to claim recourse in cases where pollution damage is caused by its contractors' or agent's actions or omissions. As fields in which the Company holds an interest straddle the boundary between the NCS and the UKCS, the Company could also be subject to UK law and regulations with respect to any incidents in those fields.
Any of the above circumstances could materially and adversely affect its business, results of operations, cash flow and financial condition.
The oil and gas industry is very competitive. Competition is particularly intense in the acquisition of (prospective) oil and gas licenses. Our competitive position depends on its geological, geophysical and engineering expertise, financial resources, ability to develop its assets and ability to select, acquire, and develop proved reserves. Many such companies not only engage in the acquisition, exploration, development and production of oil and gas reserves, but also carry on refining operations and market refined products. In addition, the Company competes with major oil and gas companies and other companies within industries supplying energy and fuel in the marketing and sale of oil and gas to transporters, distributors and end users, including industrial, commercial, and individual consumers. The Company also competes with other oil and gas companies in attempting to secure drilling rigs and other equipment necessary for drilling and completion of wells. Such equipment may be in short supply from time to time. In addition, equipment and other materials necessary to construct production and transmission facilities may be in short supply from time to time. Finally, companies and private equity firms not previously investing in oil and gas may choose to acquire reserves to establish a firm supply or simply as an investment. Any such companies will also provide competition for the Company. As a result of this competitive environment, the Company may be unable to acquire suitable licenses or licenses on terms that the Company considers acceptable. As a result, its revenues may decline over time, thereby materially and adversely affecting its business, results of operations, cash flow and financial condition.
The oil and gas industry is characterized by rapid and significant technological advancements and the introduction of new products and services using new technologies. As others use or develop new technologies, the Company may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other oil and gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages, which may in the future allow them to implement new technologies before the Company can. The Company may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies the Company uses now or in the future were to become obsolete, its business, prospects, financial condition and results of operations could be materially adversely affected. In addition, any new technology that the Company implement may have unanticipated or unforeseen adverse consequences, either to its business or the industry as a whole.
Through its development projects, the Company has built up a significant tax balance that can be utilized against future production revenues. There is no assurance that future political conditions in Norway will not result in the government adopting different policies for petroleum taxation. In the event there are changes to this tax regime, it could lead to new investments being less attractive and prevent the Company from further growth.
Furthermore, the amounts of taxes the Company must pay could also change significantly as a result of new interpretations of the relevant tax laws and regulations or changes to such laws and regulations. In addition, tax authorities could review and question its tax returns leading to additional taxes and tax penalties which could be material.
The Norwegian Government is currently implementing tax reform in Norway. The tax reform has, inter alia, led to a reduction in the general corporate tax rate, while the special petroleum tax rate has been increased. The overall effect of the rate changes for the petroleum sector is that the total marginal tax rate of 78% has remained unchanged. Further tax reform may result in changes in the Norwegian tax system (which may include changes in the tax treatment of interest costs and to withholding taxes) that may affect its current and future tax positions, net income after tax and financial condition.
Separately, within the current tax regime the Norwegian tax authorities may take a different view from the Company as to whether costs qualify as deductible exploration costs eligible for a tax refund or the law may change as to what costs qualify as deductible exploration costs or whether a tax refund may be obtained in respect of such costs. In that event, the Company may not be able to claim tax refunds for all of its exploration costs, (including costs relating to its drilling units). To the extent its assumptions as to what tax refunds may be obtained in respect of exploration costs are wrong (due to a successful challenge by the tax authorities or a change in law), its results of operations and financial condition could be materially adversely affected.
Pursuant to the current Norwegian Tax Administration Act, the Norwegian tax authorities may change a taxpayer's tax assessment within five years after the end of the tax year (or ten years in a severe penalty tax case or upon notice of criminal tax evasion). Even though the Company is of the opinion that the Company has provided the tax authorities with correct and complete information, there can be no assurance that the tax authorities will not change, or at least claim to have the authority to change, its assessment from previous tax years within this time limit (See 1.2 Risks Relating to the Industry in which the Group and Hess Norge Operates - The Company may not be able to realize the value of the tax positions within Hess Norge).
Our production of oil and gas is concentrated in a limited number of offshore fields. If mechanical or technical problems, storms or other events or problems affect the production on one of these offshore fields, it may have direct and significant impact on a substantial portion of its production or if the actual reserves associated with anyone of its fields are less than the estimated reserves, its results of operations and financial condition could be materially adversely affected.
Any decrease in production volumes or reserve estimates in the Alvheim, Bøyla, Vilje and Volund fields and/or in the Ivar Aasen field, and/or Valhall, Hod, Ula, Tambar/Tambar East and Skarv may adversely affect its results of operation and financial condition. Moreover, the Company and the other license participants have made and will continue to make significant capital expenditures with regard to the subsea development of these fields and their related facilities. Any cost overruns or delays in the subsea development or in completion and delivery of these facilities could have a material adverse effect on its business, results of operations, cash flow and financial condition. Further, if the current agreements the Company has in place pursuant to which the Company sells crude oil from these fields for any reason should be
terminated or expire, a contract with a new buyer may not be signed at the time its existing contract terminates, or the sale price the Company obtains for the crude may be significantly less than that currently paid to it, or the volumes of production a buyer is required to take could be reduced.
Further, while the Company expects that a large proportion of its future production will come from Johan Sverdrup field, future production may not be substantially in line with its projections. Certain of its material licenses are in various phases of development without current production, including Johan Sverdrup, one of its key development projects. The early stages, being the exploration or development period of a license, are commonly associated with higher risk, requiring high levels of capital expenditure without a commensurate degree of certainty of a return on that investment. Our capital expenditures may not guarantee the successful production of oil and gas in line with its projections. Other events, such as unexpected drilling conditions, equipment failures or accidents, breaches of security, adverse weather and the unavailability of drilling rigs, among others, in the fields in which the Company has an interest could, similarly, adversely affect its results of operations and financial condition.
The Company is sensitive to any shutdown or other technical issues on the Alvheim FPSO due to the fact that all of the Alvheim Area Fields are produced via the Alvheim FPSO vessel. The Company is also sensitive to any shutdown or other technical issues on the Skarv FPSO. Furthermore, the Company is also sensitive to a shutdown or other technical issue on all its producing fields (e.g., with respect to platform shutdowns). The Company has facility insurance and loss of production insurance for all its producing fields. The insurance program the Company has in place may be insufficient to offset the impact of any accidental shutdown of any of the fields. A shutdown or other technical issues on either the Alvheim FPSO or the Skarv FPSO, or its platforms, or other problems relating to its production of oil and gas causing a reduction in production levels, may, however, materially adversely affect its profitability, as a result of the increase in costs and reduction in income which normally result from such delays and through claims for compensation from third parties. Delays may also result in cancellation of contracts, which may in turn adversely affect its business, results of operations, cash flow and financial condition. For example, production from the Alvheim Area Fields for the three months ended 30 September, 2017 was processed through the Alvheim FPSO and accounted for 52% of its production for the period.
According to the Norwegian Petroleum Act, unitization is required if a petroleum deposit extends over several production licenses and these production licenses have a different ownership representation. Consensus must be achieved between the licensees on the most rational coordination of the joint development and ownership distribution of the petroleum deposit, which must be set out in an agreement regulating the joint development, production, utilization and cessation of the petroleum activities related to the licenses. If such consensus is not reached within reasonable time, the MPE may determine how such joint petroleum activities shall be conducted, including the apportionment of the deposit, which may diverge from the other participants' recommendations. In 2015, for example, the MPE made a decision on the distribution of ownership interests in the Johan Sverdrup field following arbitration between the field participants before the Norwegian Petroleum Directorate ("NPD"). The decision awarded the Company a total ownership interest in the Johan Sverdrup field of 11.5733%.
Unitization agreements relating to its production licenses can typically also include a redetermination clause, stating that the apportionment of the deposit between licenses can be adjusted within certain agreed time periods. This is, for example, the case for the unitization agreement for Johan Sverdrup according to which a redetermination process may be initiated by either of the unit interest holders beginning in 2025. Any such determination or redetermination of the Company's interest in any of its licenses may have a negative effect on its interest in the unitized deposit, including its unit interest, the tract participation in which the Company holds an interest and cash flow from production. No assurance can be made that any such determination or redetermination will be satisfactorily resolved, or will be resolved within reasonable time and without incurring significant costs. Any determination or redetermination negatively affecting its interest in a unit may have a material adverse effect on its business, results of operations, cash flow, financial condition and prospects.
Our on-going development projects involve advanced engineering work, extensive procurement activities and complex construction work to be carried out under various contract packages at different locations onshore. Furthermore, the Company (together with the other license participants), must carry out drilling operations, install, test and commission offshore installations and obtain governmental approval to take them into use, prior to commencement of production. The complexity of its development projects makes them sensitive to circumstances which may affect the planned progress or sequence of the various activities, as this may result in delays or cost increases. This also applies to its early stage development of Johan Sverdrup. Johan Sverdrup is a large, complex, multi-facility early stage development. The Johan Sverdrup development, operated by Statoil, is currently in its first phase, which encompasses the installation of four fixed platforms, oil and gas export pipelines, electrical power from shore and subsea infrastructure. At the final investment decision in early 2015, the gross capital investment for the first development phase was estimated by Statoil
at NOK 123 billion nominal and expected completion in late 2019. The gross cost estimate for the first development phase was reduced to NOK 92 billion during 2017.
Our current or future projected target dates for production may be delayed and significant cost overruns may incur due to delays, changes in any part of its development projects, technical difficulties, project mismanagement, equipment failure, natural disasters, political, economic, taxation, legal, regulatory or social uncertainties, piracy, terrorism, visa issues, protests or cyber security attacks, which again may materially adversely affect its future business, operating results, financial condition and cash flow. Ultimately, there are risks that the rights granted under its licenses or agreements with the government may be forfeited and the Company may be liable to pay large penalty sums, which could jeopardize its ability to continue operations.
Going forward, the Company, or the operator of licenses in which the Company has an interest, may be unable to explore, appraise or develop petroleum operations, or the development or production of oil and/or gas may be delayed as a result of, among other things, activities such as the failure of the other license participants and counterparties to obtain equipment, equipment failure, natural disasters, political, economic, taxation, legal, regulatory or social uncertainties, piracy, terrorism, visa issues or protests. Moreover, the other license participants and counterparties consist of a diverse base with no single material source of credit risk. A general downturn in financial markets and economic activity may result in a higher volume of late payments and outstanding receivables, which may in turn adversely affect its business, results of operations, cash flows and financial condition.
Furthermore, its estimated exploration costs are subject to a number of assumptions that may not materialize. Any such inability to explore, appraise or develop petroleum operations or non-materialization of assumptions regarding exploration costs, may have a material adverse effect on its growth ambitions, future business and revenue, operating results, financial condition and cash flow.
While the Company generally enjoys good labor relations with its employees, strikes, labor disruptions and other types of conflicts with employees including those of its independent contractors or their unions may occur at its operations. Labor disruptions may be used not only for reasons specific to its business, but also to advocate labor, political or social goals. Any such disruptions or delays in its business activities may result in increased operational costs or decreased revenues from delayed or decreased (or zero) production and significant budget overruns. If such disruptions are material, they could materially adversely affect its business, results of operations, cash flow and financial condition.
All exploration and production licenses for the NCS have incorporated detailed and mandatory work programs that are required to be fulfilled within a specific timespan. These may include seismic surveys to be performed, wells to be drilled, development decisions to be taken etc. Failure to comply with the obligations under the licenses may lead to fines, penalties, restrictions, revocation of licenses and termination of related agreements, which could materially and adversely affect its business, results of operations, cash flows and financial condition.
A failure to comply with the payment obligations (cash calls) under the standard joint operating agreements for its licenses, may lead to penal interest on the defaulted amount, loss of voting rights and information within the license and a right for the other licensees to acquire its participant interest on terms that are unfavorable to the Company and disconnected from the value of the license interest. All such sanctions could materially and adversely affect the Company's business, financial conditions and results of operations.
Where the Company is not the operator of a license, although the Company may have consultation rights or the right to withhold consent in relation to significant operational matters depending on the level of its interest in such license (as most decisions by the management committee only require a majority vote), the Company has limited control over management of the assets and mismanagement by the operator or disagreements with the operator as to the most appropriate course of action may result in significant delays, losses or increased costs to it.
The terms of the relevant operating agreements generally impose standards and requirements in relation to the operator's activities. However, there can be no assurance that such operators will observe such standards or requirements and this could result in a breach of the relevant operating agreement.
There is a risk that other participants with interests in its licenses may not be able to fund or may elect not to participate in, or consent to, certain activities relating to those licenses which require such participant's consent, including but not limited to, decisions relating to drilling programs, such as the number, identity and sequencing of wells, appraisal and development decisions, decisions relating to production and also any decision to not drill at all (e.g., "drill or drop" decisions). In these circumstances, it may not be possible for such activities to be undertaken by it alone or in conjunction with other participants at the desired time or sequence or at all. Inversely, decisions by the other participants to engage in certain activities as noted in the preceding sentence, may also be contrary to its desire not to engage in or commence such activities and may require the Company to incur its share of costs in relation thereto, which may become significant, or that the other participants may enforce decisions which will delay or affect the profitability of a project. This is especially an inherent risk in fields under development where the Company only holds a minority interest, as the management committee makes all the decisions from planning to operations of the project licenses.
Other participants in its licenses may default on their obligations to fund capital or other funding obligations in relation to the assets. In such circumstances, the Company may be required under the terms of the relevant operating agreement or otherwise to contribute all or part of such funding shortfall ourselves. The Company may not have the resources to meet these obligations.
Any disagreement, absence of consent, delay, opposition, breach of agreement, or inability to undertake activities or failure to provide funding of the kind identified above could materially adversely affect its business, results of operations, cash flow and financial condition.
Failure of other license participants to comply with obligations under the relevant licenses pursuant to which the Company operates, may lead to fines, penalties, restrictions and revocation of the license. Further, the license participants are jointly and severally responsible to the Norwegian Government for financial obligations arising out of petroleum activities pursuant to such license. Hence, if one or more of the other licensees fails to cover their share of a license cost (e.g. related to the mandatory work program or decommissioning liability), the Company can be held liable for such licensee's share of the relevant cost.
If any of the other license participants become insolvent or otherwise unable to pay debts as they come due, the license interest awarded to them may be revoked by the relevant government authority who will then reallocate the license interest. Although the Company anticipates that the relevant government authority may permit the Company to continue operations at a field during a reallocation process, there can be no assurance that the Company will be able to continue operations pursuant to these reclaimed licenses or that any transition related to the reallocation of the license would not materially disrupt its operations or development or productions schedule. The occurrence of any of the situations described above could materially and adversely affect its business, results of operations, cash flow and financial condition.
Market conditions may also impair the liquidity situation of contractors and consequently their ability to meet their obligations to the Company. This may in turn impact both project timelines and cost. The incurrence of cost overruns or delays could have a material adverse effect on its business, results of operations, cash flow and financial condition
The Company is operator for several of its licenses. Although the operatorship is performed based on a "no gain, no loss" principle, the other license participants are provided with audit rights and other rights that may ultimately inflict losses on the Company as an operator should the Company be found not to have managed the operatorship in compliance with relevant requirements. The incurrence of such losses could have a material adverse effect on its business, results of operations, cash flow and financial condition.
The Company is, as other exploration and production companies, reliant upon services, goods and equipment provided by contractors and other companies to carry out its operations. As there are numerous material projects to be carried out on the NCS in the years to come, there is a continuing risk for capacity constraints and cost inflation in the service sector. If The Company is unable to obtain the services, goods or equipment necessary to carry out its operations (including its current and planned exploration and development projects), or if any of its contractors are unable or unwilling to carry out its services or deliver goods or equipment to The Company as planned or otherwise become unable to respect their obligations, become insolvent or otherwise unable to pay debts as they come due, The Company's operations or projects may suffer from delays and a subsequent decrease in net production revenue which may materially adversely affect The Company's business, results of operations, cash flow and financial condition.
Market conditions may impair the liquidity situation of contractors and consequently their ability to meet their obligations towards the Company. This could materially adversely affect the Company's business, operating results, cash flow and financial condition.
The Company depends on capacity (whether through pipelines, tankers or otherwise) to transport and sell its oil and gas production. The Company, or the license group in which the Company holds an interest, may need to rely on access to third-party infrastructure to be able to transport produced oil and gas (e.g., by depending on obtaining approval for construction of pipelines in close proximity to or crossing third-party infrastructure or being able to acquire the necessary capacity to transport gas). There can be no assurance that the Company will be able to get access to necessary infrastructure at an economically justifiable cost or access necessary infrastructure at all. For example, Marathon Norway did not hold any future booking capacity in Gassled nor any long-term National Transmission System ("NTS") entry capacity to bring gas into NTS through aggregated system entry points such as at St. Fergus in Scotland through the Scottish Area Gas Evacuation ("SAGE") pipeline system. If access to third-party infrastructure and necessary capacity bookings are unavailable or unavailable at an economically justifiable cost, the Company's income relating to the sale of oil and gas may be reduced, which may materially adversely affect the Company's business, results of operations, cash flow and financial condition.
There are significant uncertainties relating to the estimated costs for decommissioning of its current licenses including the schedule for removal of each installation and performance of other decommissioning activities. For example, the Jette, Jotun and Varg fields all ceased production in the year ended December 31,2016, and the Company also plans to perform plug and abandonment operations on producing fields in the near future, as well as the Valhall field in 2017. Our decommissioning liability increased significantly due to the acquisition of BP Norge. Further, the Company is liable for its share of costs related to the removal and abandonment of certain gas transportation facilities owned by Gassled, a Norwegian joint venture owned by a number of oil and gas companies operating on the NCS. Additionally, the original Valhall riser platform at Ekofisk ceased production in 1998, and the topside was removed in July 2016, while the jacket remains to be removed. The Valhall license has a decommissioning program underway. Planning has started for decommissioning and the removal of certain platforms, and the plugging and abandonment of certain Valhall wells commenced in 2014. Furthermore, the limited examples of current asset decommissioning activities on the NCS increases the estimation uncertainty of decommissioning costs and liabilities. No assurance can be given that the anticipated costs and time of removal are correct and any deviation from such estimates may have a material adverse effect on its business, results of operations, cash flow and financial condition.
Also, under the Norwegian Petroleum Act, licensees are responsible towards the Norwegian Government for making sure that a decision relating to disposal is carried out, unless otherwise decided by the Ministry. Within the joint venture, the licensees are: (i) primarily liable to each other on a pro-rata basis and (ii) secondarily jointly and severally liable for all decommissioning obligations arising by virtue of the joint venture's activities.
In Norway, there is no obligation or tradition for license participants to provide security for their respective share of any decommissioning liabilities ahead of actual decommissioning. Hence, if one or more of the other licensees fail to cover their share of decommissioning costs, the Company can be held liable for such licensee's share of such costs without the ability to rely or draw down on any security a defaulting licensee may have previously provided. Furthermore, under the Norwegian Petroleum Act, a licensee assigning its interest in a license remains secondarily liable for decommissioning costs related to facilities existing at the time of assignment in the event that the decommissioning costs are not covered by the current licensees. Any significant increase in decommissioning costs relating to its current or previous licenses may materially and adversely affect its business, results of operations, cash flow and financial condition. Certain fields in which the Company holds an interest straddle the boundary between the UKCS and the NCS. Even though its interests are in the Norwegian sector, the Company may still have responsibilities under or become liable for decommissioning obligations under UK legislation. In particular, the Company may be liable for the full costs of decommissioning any offshore installation located in the UK if its own production is recovered or stored by owners of such installation.
The oil and gas industry in general is subject to extensive government policies and regulations. No assurance can be given that existing legislation or new interpretation of existing legislation, will not result in a curtailment of production, delays or a material increase in operating costs and capital expenditure of its activities or otherwise adversely affect its financial condition, results of operations or prospects. Further, a failure to comply with applicable legislation, regulations and conditions or orders issued by the regulatory authorities, may lead to fines, penalties, restrictions, withdrawal of licenses and termination of related agreements, which could have the same effect on its business, results of operations, cash flow and financial condition.
The Company conducts exploration and development activities in Norway and are dependent on receipt of government approvals and permits to develop its assets. The Norwegian Petroleum Act, among other things, sets out different criteria for the organization, competence and financial capability that a licensee at the NCS must fulfill at all times. The Company is qualified to conduct its operations on the NCS, however, there is no assurance that
future political conditions in Norway will not result in the government adopting new or different policies and regulations on exploration, development, operation and ownership of oil and gas, environmental protection, and labor relations. Further, the Company may be unable to obtain or renew required drilling rights, licenses, permits and other authorizations and these may also be suspended, terminated or revoked prior to their expiration. This may affect the Company's ability to undertake exploration and development activities in respect of present and future assets, as well as its ability to raise funds for such activities. Also, there can be no assurance that the Company's licenses granted by the MPE will be extended or will not be revoked in the future. Furthermore, there is a risk that the MPE stipulates conditions for any such extension or for not revoking any licenses. Lack of governmental approvals or permits or delays in receiving such approval may delay its operations, increase its costs and liabilities or affect the status of its contractual arrangements or its ability to meet its contractual obligations. Any of the above factors may have a material adverse effect on its business, results of operations, cash flow and financial condition.
Our exit strategy in relation to any particular oil and gas interest may be subject to the prior approval of the other license participants pursuant to joint operating agreements ("JOA"), unitization agreements and approval from the MPE and MoF, thus restricting its ability to dispose of, sell or transfer a license interest and make funds available when needed.
If the mandatory work obligations set by the MPE in the licenses have not been carried out, assignment of its participant interest in a license is subject to the approval of the management committee in the license. Further, any transfer of a license interest is subject to approval by the MPE and the Norwegian MoF. Whether such approval will be given may be determined by the stage of the relevant project (whether the license is in the exploration, development or production phase), outstanding obligations, the potential buyers, political conditions in Norway and applicable policies and regulations on exploration, development and operation on the NCS. Further, under applicable Norwegian law, the Company may be subject to secondary liability for decommissioning costs in relation to licenses that have been sold by the Company if the buyer should default on his license obligations.
The Company is vulnerable to adverse market perception as it must display a high level of integrity and maintain the trust and confidence of investors, the other license participants, public authorities and counterparties. Any mismanagement, fraud or failure to satisfy fiduciary or regulatory responsibilities, allegations of such activities, or negative publicity resulting from such other activities, or the association of any of the above with Aker BP could materially adversely affect its reputation and the value of its brand, as well as its business, results of operations, cash flow and financial condition.
All phases of the oil and gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of international conventions and state and municipal laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, and releases or emissions of various substances produced in association with oil and gas operations. The legislation also requires that wells and facility sites are operated, maintained, abandoned, and reclaimed to the satisfaction of applicable regulatory authorities. The Company is subject to legislation in relation to the emission of carbon dioxide, methane, nitrous oxide and other socalled greenhouse gases. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material, in addition to loss of reputation. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability, and potentially increased capital expenditures and operating costs. The discharge of oil, gas or other pollutants into the air, soil or water may give rise to material liabilities to foreign governments and third parties and may require the Company to incur material costs to remedy such discharge. No assurance can be given that environmental laws will not result in a curtailment or shut down of production or a material increase in the costs of production, development or exploration activities or otherwise materially adversely affect the Company's business, results of operations, cash flow and financial condition.
Furthermore, environmental concerns relating to the oil and gas industry's operating practices are expected to increasingly influence government regulation and consumption patterns which favor cleaner burning fuels such as gas. Future compliance with existing emissions legislation or any future emissions legislation could adversely affect its profitability. Future legislative initiatives designed to reduce the consumption of hydrocarbons could also have an impact on the ability of the Company to market its oil and gas and the prices which the Company is able to obtain, which in turn may adversely affect its business, results of operations, cash flow and financial condition.
The Company has been operating in the oil and gas business for several years. While the Company is not currently aware of any material pollution or environmental liabilities in relation to its operations on the NCS, it may potentially be subject to various liabilities such as pollution and environmental liabilities related to its business.
Over the past several years, its operations have expanded to include several fields in the Barents Sea. Arctic drilling presents a unique operating environment characterized by remoteness, the lack of ancillary supporting infrastructure, the presence of sea ice, extended periods of darkness and cold, and hurricane-strength storms. These factors make operations in the Arctic difficult, result in increased operating costs, and also increase the risk of incidents resulting from its operations, such as oil spills. In addition, the Arctic Ocean is an ecologically sensitive area, and any spills or other environmental incidents that may occur could result in increased response and remedial costs and other liabilities. Any spills in the eastern section of the Barents Sea may also cross the border into Russian waters. Moreover, environmental non-governmental organizations ("NGOs") frequently oppose Arctic drilling. These NGOs could initiate legal or other actions that may delay its exploration and production activities in this area. Any of the above factors could have a material adverse effect on its business, results of operations, cash flow, financial condition and prospects.
Our business and results of operations could be adversely affected by climate change and the adoption of new climate change laws, policies and regulations. Growing concerns about climate change and greenhouse gas emissions have led to the adoption of various regulations and policies, including the Paris Agreement negotiated at the 2015 United Nations Conference on Climate Change ("COP 21 "), which requires participating nations to reduce carbon emissions every five years beginning in 2023. Multiple plans have also been proposed in the Norwegian parliament to reduce carbon emissions from companies operating in certain sectors, including the oil and gas industry, and create a carbon trading system linked to the European Union's emissions trading scheme. For example, in June 2017, the Norwegian Parliament passed legislation that seeks to reduce carbon emissions from 1990 levels by at least 40% by 2030. In addition, Norway has announced its intention to phase out the sale of fossil fuel powered vehicles in favor of electric vehicles by 2025. The emission reduction targets and other provisions of the recent Norwegian climate change law, the Paris Agreement, or similar legislative or regulatory initiatives enacted in the future, could adversely impact its business by imposing increased costs in the form of taxes or for the purchase of emission allowances, limiting its ability to develop new oil and gas reserves, decreasing the value of its assets, or reducing the demand for hydrocarbons and refined petroleum products. For example, on October 18, 2016, the environmental organizations Greenpeace Norden and Nature fr Youth (Natur og Ungdom) submitted a writ of summons to the Oslo District Court claiming that the Norwegian Government's decision on awarding production licenses in the 23rd licensing round was invalid. The defendant in the case is the Government of Norway represented by the Ministry of Petroleum and Energy. The government disputes the claim and submitted its defense to the Oslo District Court in December 2016. The case was heard between 14 and 22 November 2017. Normally it can be expected for the court to make its decision within year end 2017, but given the holidays in December, the judgement might not be available until the beginning of 2018. The case concerns the constitutional and procedural validity of the Norwegian Government's decision to offer 13 companies ten production licenses in the 23rd licensing round. The main question is to what degree the Norwegian Constitution provides substantive protection of the environment, and whether or not the Constitution sets out an absolute threshold for the negative environmental impacts tolerable. Although the Company is not a party to the dispute, the Company did receive three licenses (which are in the initial exploration phase as of the date of this Information Memorandum) in the disputed 23rd licensing round. If the claimants are successful, the outcome of the case may adversely affect its business.
Additionally, some scientists have concluded that increasing concentrations of greenhouse gases in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. Our offshore operations are particularly at risk from severe climatic events. If any such climate changes were to occur, they could have an adverse effect on its financial condition and results of operations.
Oil and gas exploration, development, and production operations are subject to all the risks and hazards typically associated with such operations, including, but not limited to fires, explosions, blowouts, and oil spills, each of which could result in substantial damage to oil and gas wells, production facilities, other property, and the environment, or result in personal injury and business interruption. The Company maintains a number of separate insurance policies to protect its core businesses against loss and liability to third parties. Insured risks typically include general liability, workers' compensation and employee liability, professional indemnity and material damage. Furthermore, not all mentioned risks are insurable, or only insurable at a disproportionately high cost. Although the Company maintains liability insurance in an amount that it consider adequate and consistent with industry standard, the nature of these risks is such that liabilities could materially exceed policy limits or not be insured at all, in which event the Company could
incur significant costs that could have adverse effect on its financial condition, results of operation and cash flow. Any uninsured loss or liabilities, or any loss and liabilities exceeding the insured limits, may adversely affect the Company's business, results of operations, cash flow and financial condition.
Oil and gas exploration and development activities are dependent on the availability of specialized equipment, including, but not limited to drilling and related equipment in the particular areas where such activities will be conducted. From time to time the demand for limited equipment may be high or access restrictions will affect the availability and cost of such equipment, and from time to time may delay exploration and development activities. Also, to the extent the Company is not the operator of its oil and gas assets, the Company will be dependent on such operators for the timing of activities related to such assets and will be largely unable to direct or control the activities of the operators. If any of these risks materialize, they may have a material adverse effect on its business, results of operations, cash flow and financial condition.
The reserves set forth in this Information Memorandum represent estimates only and are based on a technical expert's reports. In addition, the resources set forth in this Information Memorandum represent management's estimates. The standards utilized to prepare the commercial reserves and contingent resources information that has been included in this Information Memorandum, are different from the standards of reporting adopted in other jurisdictions. Investors, therefore, should not assume that the data found in the reserves and resources information set forth in this Information Memorandum is directly comparable to similar information that has been prepared in accordance with the reserve and resource reporting standards of other jurisdictions.
In general, estimates of economically recoverable oil reserves and resources are based on a number of factors and assumptions made as of the date on which the reserves estimates were determined, such as geological and engineering estimates (which have inherent uncertainties), historical production from the properties, the assumed effects of regulation by governmental agencies and estimates of future commodity prices and operating costs, all of which may vary considerably from actual results.
Underground accumulations of hydrocarbons cannot be measured in an exact manner and estimates thereof are a subjective process aimed at understanding the statistical probabilities of recovery. Estimates of the quantity of economically recoverable oil and gas reserves, rates of production and the timing of development expenditures depend upon several variables and assumptions, including the following:
As all reserve estimates are subjective, each of the following items may differ materially from those assumed in estimating reserves:
Many of the factors in respect of which assumptions are made when estimating reserves are beyond its control and therefore these estimates may prove to be incorrect over time. Evaluations of reserves necessarily involve multiple uncertainties. The accuracy of any reserves or resources evaluation depends on the quality of available information and oil and gas engineering and geological interpretation. In preparing its reserve reports, AGR relied on estimates of costs,
production profiles and economic models supplied by the Company and by third parties, such as Statoil and the Norwegian government, the accuracy of which cannot be guaranteed. Drilling, interpretation, testing and production after the date of the estimates may require substantial upward or downward revisions in its reserves or resources data. Moreover, different reserve engineers may make different estimates of reserves and cash flows based on the same available data. Actual production, revenues and expenditures with respect to reserves and resources will vary from estimates and the variances may be material.
The uncertainties in relation to the estimation of reserves summarized above also exist with respect to the estimation of resources. The probability that contingent resources will be economically recoverable, is considerably lower than for commercial reserves. Volumes and values associated with contingent resources should be considered with higher uncertainty than volumes and values associated with reserves.
If the assumptions upon which the estimates of its oil and gas reserves and resources have been based prove to be incorrect or if the actual reserves or recoverable resources available to the Company are otherwise less than the current estimates or of lesser quality than expected, the Company may be unable to recover and produce the estimated levels or quality of oil and gas set out in this Information Memorandum and this may materially and adversely affect its business, prospects, financial condition and results of operations.
IFRS requires that management apply certain accounting policies and make certain estimates and assumptions, which affect reported amounts in the consolidated financial statements of the Company. The accounting policies may result in non-cash charges to net income and material write downs of net assets in the financial statements. Such non-cash charges and write downs may be viewed unfavourably by the market and result in an inability to borrow funds and/or may result in a significant decline in the trading price of the Company's shares.
The successful development and performance of its business depends on its ability to attract and retain skilled professionals with appropriate experience and expertise. Attracting and retaining additional key personnel will assist in the expansion of its business and the loss of key employees could also have a material negative effect on its business. The Company faces significant competition for skilled personnel and there can be no assurance that it will have access to sufficient skilled and experienced professionals. This may be particularly evident for its offshore activities, where the location of its production facilities and shift work arrangements associated with offshore work, may negatively affect te Compnay's ability to attract the necessary employment resources, as skilled personnel may be reluctant to take on such assignments.
Additionally, there is no assurance that the Company will successfully attract and retain personnel required to continue to expand its business and to successfully execute its business strategy. Failure to attract or retain such employees could result in the inability to maintain the appropriate technological standard or take advantage of new opportunities that may arise, which may in turn lead to a subsequent decline in competitiveness and could materially adversely affect its business, results of operations, cash flow and financial condition.
The Company faces the risk of litigation and other proceedings in relation to its business. The outcome of any litigation may expose the Company to unexpected costs and losses, reputational and other non-financial consequences and diverting management attention, which may in turn adversely affect the Company's business, results of operations, cash flow and financial condition.
There are potential conflicts of interest to which the directors, officers and principal shareholders may be subject to in connection with the Company's operations. Some of its directors, officers and principal shareholders are or may become engaged in other oil and gas interests (including interests relating to oil and gas services) on their own behalf and on behalf of other companies resulting in a conflict of interest and situations may arise where the directors and officers will be in direct competition with Aker BP. Such conflicts, if any, will be subject to the procedures and remedies under Norwegian company law, petroleum law and general Norwegian law, but may not prevent adverse effects for the Company with regard to such conflicts. The Company's directors, officers and principal shareholders may not devote their time on a full-time basis to the affairs of Aker BP as a result of such conflicts. Certain members of the board of directors and senior management own collectively, directly and indirectly, a significant part of the outstanding share capital of the Company, and will therefore have the possibility to influence the decision-making in the Company.
The Company makes and expect to continue to make substantial capital expenditures in its business for the development, production and acquisition of oil and natural gas reserves. The Company intends to finance the majority of its future capital expenditures with cash flow from operations and borrowings under its RBL Facility and other debt facilities. The Company's cash flows from operations and access to capital are subject to a number of variables which it does not control, including:
If the Company's revenues or the borrowing base under its RBL Facility decrease as a result of lower oil or gas prices, operating difficulties, declines in reserves or for any other reason, the Company may have limited ability to obtain the capital necessary to sustain its operations at current levels. The Company's RBL Facility, the NOK Bond and, to a lesser extent, the US HY Bond restrict its ability to obtain certain types of new financing. If additional capital is needed, the Company may not be able to obtain additional debt or capital required. If cash generated by operations or cash available under the Company's RBL Facility or other debt facilities (see Section 3.8 "Capital Resources") is not sufficient to meet its capital requirements, the failure to obtain additional financing could result in a curtailment of its operations relating to development of its prospects, which in turn could lead to a decline in the Company's oil and natural gas reserves, or if it is not possible to cancel or stop a project, be legally obliged to carry out the project contrary to its desire or with negative economic impact. Further, the Company may fail to make required cash calls and breach license obligations, which again could lead to adverse consequences, see "Risks relating to its business-Our exploration and production operations are dependent on its compliance with obligations under licenses, joint operating agreements and field development plans". All of the above could adversely affect the Company's production, revenues and results of operations as well as having an adverse effect on its ability to service its indebtedness.
The Company is exposed to market fluctuations in foreign exchange rates. Revenues are in U.S. dollars for oil and in euros and pounds sterling for gas, while operational costs, taxes and investment are in several other currencies, including Norwegian kroner. Significant fluctuations in exchange rates between U.S. dollars and Norwegian kroner may materially adversely affect the reported results.
The Company could be a target of cyber-attacks designed to penetrate its network security or the security of its internal systems, misappropriate proprietary information, commit financial fraud and/or cause interruptions to its activities, including a reduction or halt in its production. Such attacks could include hackers obtaining access to the Company's systems, the introduction of malicious computer code or denial of service attacks. If an actual or perceived breach of the Company's network security occurs, it could adversely affect the Company's business or reputation, and may expose it to the loss of information, litigation and possible liability. Such a security breach could also divert the efforts of the Company's technical and management personnel. In addition, such a security breach could impair the Company's ability to operate its business and provide products and services to its customers. If this happens, the Company's reputation could be harmed, its revenues could decline and its business could suffer.
In addition, confidential information that the Company maintains may be subject to misappropriation, theft and deliberate or unintentional misuse by current or former employees, third-party contractors or other parties who have had access to such information. Any such misappropriation and/or misuse of its information could result in the Company, among other things, being in breach of certain data protection and related legislation. The Company expects that it will need to continue closely monitoring the accessibility and use of confidential information in its business, educate its employees and third-party contractors about the risks and consequences of any misuse of confidential information and, to the extent necessary, pursue legal or other remedies to enforce its polices and deter future misuse.
The trading price of the Shares could fluctuate significantly in response to a number of factors beyond the control of the Company, including quarterly variations in operating results, adverse business developments, changes in financial estimates and investment recommendations or ratings by securities analysts, announcements by competitors of new
product and service offerings, significant contracts, acquisitions or strategic relationships, publicity about their products and services or their competitors, lawsuits, unforeseen liabilities, changes to the regulatory environment or general market conditions.
The Company's ability to distribute dividends is subject to financial capacity and absence of restrictions under loan agreements and other restrictions.
The market value of the Shares can fluctuate significantly and may not always reflect the underlying asset value of the Company. A number of factors outside the control of the Company may have an impact on its performance and the price of the Shares. Such factors include but are not limited to a change in market sentiment regarding the Shares and the Company, the operating and share price performance of other companies in the industry and markets in which the Company operates, speculation about the Company's business in the press, media or investment community, changes to the Company's profit estimates, the publication of research reports by analysts and general market conditions. If any of these factors actually occurs, this may have a material adverse effect on the pricing of the Shares.
The market price of the Shares could decline as a result of sales of a large number of Shares in the market or the perception that these sales could occur.
It is possible that the Company may in the future decide to offer shares or other securities in order to finance new capital-intensive projects, in connection with unanticipated liabilities or expenses or for any other purposes. Any such offering could reduce the proportionate ownership and voting interests of holders of shares, as well as the earnings per share and the net asset value per share, and any offering could have a material adverse effect on the market price of the shares.
Beneficial owners of Shares that are registered in a nominee account (such as through brokers, dealers or other third parties) may not be able to vote for such shares unless their ownership is (a) re-registered in their names with the VPS, prior to the Company's general meetings or (b) the registered nominee holder grants a proxy to such beneficial owner in the manner provided in the Articles of Association in force at that time and pursuant to the contractual relationship, if any, between the nominee and the beneficial owner, to vote for such Shares. The Company cannot guarantee that beneficial owners of the Shares will receive the notice of a general meeting of shareholders of the Company in time to instruct their nominees to either effect a re-registration of their Shares or otherwise vote for their Shares in the manner desired by such beneficial owners. Any persons that hold their Shares through a nominee arrangement should consult the nominee to ensure that any Shares beneficially held are voted for in the manner desired by such beneficial owner.
The Shares have not been registered under the U.S. Securities Act or any U.S. state securities laws or any other jurisdiction outside of Norway and are not expected to be registered in the future. As such, the Shares may not be offered or sold except pursuant to an exemption from the registration requirements of the U.S. Securities Act and applicable securities laws. In addition, there can be no assurances that shareholders residing or domiciled in the United States will be able to participate in future capital increases or rights offerings.
The Company's Shares are priced in NOK, and any future payments of dividends on the Shares may be denominated in NOK. Accordingly, any investor outside Norway may be subject to adverse movements in the NOK against their local currency, as the foreign currency equivalent of any dividends paid on the shares or price received in connection with any sale of the shares could be materially adversely affected.
The Board of Directors of Aker BP ASA accepts responsibility for the information contained in this Information Memorandum. The members of the Board of Directors confirm that, having taken all reasonable care to ensure that such is the case, the information contained in this Information Memorandum is, to the best of their knowledge, in accordance with the facts and contains no omissions likely to affect its importance.
Oslo, 1 December 2017
The Board of Directors of Aker BP ASA
| Øyvind Eriksen (Chairman) | Anne Marie Cannon (Deputy Chair) |
|---|---|
| Kjelllnge Røkke | Gro Gauthun Kielland |
| Trond Brandsrud | Katherine Anne Thomson |
| Bernard Looney | Terje Solheim |
| Lone Margrethe Olstad | Bjørn Thore Synsvoll Ribesen |
| Ørjan Holstad |
The Company is an oil and gas company with exploration and production activities on the NCS and is listed on the Oslo Stock Exchange under the ticker "AKERBP". The Company is a public limited liability company registered under Norwegian law and domiciled in Norway. As of the date of this Information Memorandum and prior to completion of the Transaction, the Company is primarily an offshore exploration and production company with a total of 110 licenses (64 as operator). Please see Section 3.5 "License Portfolio, Reserves and Resources" for further details.
The Company is a large independent Norwegian oil producer.
The Company had 1,371 employees as of 31 December 2016. The Company has interests in five operated production hubs, predominantly located in the North Sea area of the NCS. These include the Alvheim area (Alvheim, Bøyla, Volund and Vilje), the Ivar Aasen area, the Ula area (Ula and Tambar), the Valhall area (Valhall and Hod) and the Skarv area. In addition, the Company has interest in non-operated Gina Krog and Atla producing fields.
The Company also has an 11.5733% non-operated interest in the Johan Sverdrup development. The field is among the largest oil discoveries on the NCS, with the operator Statoil estimating the total field resources to be in the range of 2,000 to 3,000 million barrels of oil equivalent ("boe"). First oil is planned for the fourth quarter 2019. In addition, the Company has a 15 percent non-operated interest in the Oda field, a subsea tie-back to Ula with first oil expected in the second quarter 2019.
Senior Management comprises individuals with long experience from the oil and gas industry, including companies like Statoil, Aker Solutions, ConocoPhillips, BP Norge and Marathon Oil.
The organisation is based in five office locations, namely Oslo (Bærum), Trondheim, Stavanger, Sandnessjøen and Harstad. The Company's registered headquarters is in Bærum (Akerkvartalet, Oksenøyveien 10, 1366 Bærum).
The Company's total net proven reserves (P90/1P) as of 31 December 2016 is estimated at 529 million boe. The total net proven plus probable reserves (P50/2P) were estimated at 711 million boe. The Company reported a total production of 28.3 million boe in 2016 which is equivalent to an average daily production of 77,441 barrels of oil equivalent per day ("boepd").
At Aker BP, its vision is to be the leading independent offshore E&P company while maximizing shareholder value. The Company has evolved from an active exploration and development company to become a fully integrated E&P company with activities within exploration, development and production. As of the date of this Information Memorandum the Company considers itself to be one of the largest players on the NCS, with a growing resource base and production developed both organically, through its exploration and development activities, and through acquisitions, including the transformative Marathon Norge and BP Norge acquisitions. The Company is committed to optimizing its existing producing assets and delivering its near-term development projects to further increase its production. The Company is one of the largest listed European independent E&P companies measured by production, and it continuously seek to solidify and improve its position by leveraging its expertise within the Norwegian oil and gas industry.
The Norwegian oil and gas regulatory environment incentivizes the Company's long-term exploration and development goals through a favorable tax regime that allows the Company to deploy capital with limited downside. The Norwegian government has stated that it is committed to supporting exploration and development activity by Norwegian and foreign companies on the NCS and to stimulating competition, breeding technological innovation and promoting efficiency in the extraction of oil and gas resources. The Company believes there are substantial remaining resources to be discovered on the NCS and, given the supportive regulatory environment, it expects to continue to playa meaningful role in future licensing rounds.
The Company is:
Respectful - the Company has high ethical standards, the Company has respect for those the Company work with and the Company value diversity
With a market capitalization of approximately NOK 67.11 billion as of November 11, 2017, and a diverse producing portfolio of scale on the NCS, the Company believes the Company is one of the leading independent offshore EfrP companies. The Company's asset base is balanced and includes producing assets, development projects, and discoveries. During the first nine months of 2017 the Company operated 99.6% of a total reported production of 139,928 boepd, of which 22% was gas production and 78% was oil and NGL. The Company further believes its portfolio is comprised of highquality assets.
Notably, the Company has significant interests in the producing Alvheim Area Fields, the Ivar Aasen field, the Skarv field, the Ula/Tambar fields and the Valhall Area fields, and in the Johan Sverdrup field, which is currently under development. The Alvheim Area Fields have gross 2P reserves estimated at 189 MMboe (120 MMboe (net)) as of December 31,2016, and the Company sees further potential upside within existing reservoirs and near-field extensions.
The Company operates and own a 65% working interest in most of the Alvheim Area Fields (65.0% in the Norwegian part of the Alvheim field, 46.9% in the Vilje field, 65.0% in the Volund field, 65% in the Bøyla field and 57.62% in the Alvheim Boa unit, which is located partly on the UK side).
The Alvheim Area Fields produced an average of approximately 62,327 boepd (net) for the year ended December 31, 2016. The initial 2P reserve estimates at the time of PDO submission for the Alvheim, Vilje, Volund and Bøyla fields were 170.5 MMboe, 54.9 MMboe, 50.5 MMboe and 22.6 MMboe, respectively. The combined gross remaining 2P reserves and produced volumes in the Alvheim Area Fields, including Viper-Kobra, as of December 31, 2016 was 570.1 MMboe, exceeding these PDO estimates by 271.6 MMboe. The Viper-Kobra development commenced production in November 2016 and has contributed to arresting decline in the Alvheim area. Production costs at the Alvheim Area Fields were USD 5.5/boe in 2016.
The Skarv field has gross 2P reserves that the Company estimates to be 226 MMboe (54 MMboe (net)) as of December 31, 2016. The field was unitized with the adjacent Idun and Ærfugl (formerly "Snadd") gas fields in 2007. The Company operates and owns a 23.84% interest in the Skarv field. The Skarv field, which came on stream in December 2012, was acquired as part of the BP acquisition. The development wells are now on-stream producing a combination of oil, gas and gas condensate from the Skarv and Idun fields. Upside exists in the area and the Company is currently maturing a new development, Ærfugl, towards PDO. The Ærfugl discovery has been on test production since 2013, but is currently shut in because the maximum volumes from the production permit have been reached for 2017. First gas from a full field development is expected in 2020 and the Company estimates an increase in gross 2P reserves of 159 MMboe over the course of the multi-phase development of the field.
The Valhall area (including Hod) has gross 2P reserves that Company estimated to be 233 MMboe (84 MMboe (net)) as of December 31,2016. The Company operates and owns a 35.95% working interest in Valhall and 37.5% working interest in Hod. The Valhall Area consists of a mega structure containing the two fields Valhall and Hod. The gross in place volumes in the fields are estimated at about 3.8 bn boe of which 1 bn boe was produced per January 2017. Aker BP has entered into an agreement to acquire Hess Norge AS which includes 64.05% in Valhall and 62.5% in the Hod field. Aker BP will seek to sell a share of participating interest in the Valhall and Hod fields. For the nine months ended September 30, 2017, Hess Norge net production averaged 23.8 Mboed, compared to 27.9 Mboed for the year ended December 31, 2016. The transaction is subject to customary conditions for completion, including approval by the MPE, MoF relevant competition clearance. The effective date of the transaction will be 1 January 2017 (the "Effective Date"), and closing is expected by the end of 2017. Aker BP is planning to submit a Plan for Development and Operation for the Valhall Flank West project in late 2017, with estimated first oil in 2020. In addition, Aker BP is maturing a number of additional projects in the area, including the North and South Flank projects. According to the NPD, both the Skarv and Valhall fields are among the top 20 remaining fields in Norway in terms of reserves.
The Ivar Aasen Unit has gross 2P reserves that the Company estimates to be 182 MMboe (63 MMboe (net)) as of December 31, 2016. Including the Hanz deposit, the Company estimates the Ivar Aasen fields to have gross 2P reserves of 199 MMboe (69 MMboe (net)). The Company operates and owns a 34.7862% working interest in the Ivar Aasen Unit. The field came onstream in December 2016, on time, within the projected budget and without serious incidents. Average net production for the nine months ended September 30, 2017 was 16,284 boepd, exceeding its expectations. The Ivar Aasen Unit is expected to reach plateau production of 24,000 boepd (net) in 2018.
The Ula and Tambar (not inclusive of Tambar East) fields have gross 2P reserves that the Company estimates to be 76 MMboe (57 MMboe (net)) as of December 31,2016. The Company operates and owns an 80.0% working interest in Ula and
55.0% and 46.2% in Tambar and Tambar East, respectively. The Ula development consists of three bridge-linked steel jacket platforms for production, living quarters and drilling. The Tambar facility is an unmanned six slot wellhead platform tied back to Ula platform for processing and export.
As operator of most of its producing assets, the Company is well positioned to manage production performance, production costs and the nature, timing and amount of its capital expenditures. Such management promotes the timely implementation of its desired engineering and operating techniques. The Company's ability to influence the timing and pace of spending is particularly critical in light of uncertainties in the current oil price environment. The Company believes that the operating expertise and experience of its personnel is instrumental to its ability to efficiently and safely manage its production base. The majority of its key producing assets as of December 31,2016 are established fields with extensive production track records and well-understood geologies which are expected to require limited capital investment to maintain production.
The Company believes its production base is profitable, reliable and stable. In the first nine months of 2017, the Company had average production costs of USD 9.9/boe and have generated a total free cash flow in the period of USD 746 million. In addition, the Company has a loss of production insurance program for its producing fields which covers loss of production after 60 days at USD 50/bbl (net).
The Alvheim area is the main producing hub within the Company's portfolio. The area was developed by Marathon Norway using the Alvheim FPSO, which has a strong uptime track record, with production efficiency of 97% and 98% during the third and second quarter of 2017, respectively. The Alvheim Area Fields delivered an average net production of approximately 62,327 boepd from four fields (Alvheim, Bøyla, Vilje and Volund) for the year ended December 31, 2016. The Viper-Kobra field, composed of two smaller discoveries within the Alvheim field, was brought online in November 2016 and tied into the Alvheim FPSO in late 2016, further bolstering production in the Alvheim Area Fields.
The Ivar Aasen, Skarv and Valhall fields are also important, reliable producing assets within the Company's portfolio. The Ivar Aasen field was the Company's first major development project as operator, and production from the field commenced December 24, 2016, delivering higher production than initially anticipated. The Ivar Aasen Unit produced 16,298 boepd net for Aker BP in the first nine months of 2017. The Skarv field is a large asset that the Company acquired in connection with the BP acquisition in December 2016. The field came on stream in December 2012 and has a facility design life time of 25 years from start of production in 2012. The Skarv field has gross 2P reserves that the Company estimates to be 226 MMboe (54 MMboe (net)) as of December 31, 2016. The Skarv field has proved to have high production efficiency of 87% and 96% during the third and second quarter of 2017, respectively. The third quarter included planned maintenance. The Valhall field was also acquired in connection with the BP acquisition during December 2016. The field was discovered in 1975, and production began in 1982. The Valhall field has the potential for increased recovery going forward. The Valhall concession period currently expires in 2028.
The Company is leveraging its operational experience to continue its pursuit of production efficiencies and effective deployment of technology to achieve increased regularity and recovery and to realize cost savings across its operations. Furthermore, exchange rate movements compared to the US dollar have impacted the Company's NOK cost base favorably. For example, driven by continued investments, cost improvements and strong performance, among other factors, the average production costs of the Alvheim area have decreased from USD 8.2/boe in 2014 when the assets were acquired from Marathon Norway to USD 4.4/boe in the first nine months of 2017.
The Company's strategy has allowed it to steadily increase operational efficiencies and to reduce exploration, development and production costs. In the first nine months of 2017, the Company had average production costs of USD 9.9/boe. The Company believes the low-cost Ivar Aasen field, which came on stream in December 2016, will further help reduce its average production costs as it continues production. The average production costs per barrel for the Ivar Aasen field are anticipated to be between USD 9.00/boe and USD 10.00/boe, and were USD 9.6/boe for the first nine months of 2017. The Skarv field, which the Company acquired in connection with the BP acquisition during the year ended December 31, 2016, is also a low production cost asset.
Furthermore, the Company's key development asset, the Johan Sverdrup field, is expected to have low production costs. The average production costs per barrel in real terms for the Johan Sverdrup field at plateau production, expected in 2023, is estimated to be between USD 2.00/boe and USD 3.00/boe. The Company believes that these low production costs and projected capital expenditures are competitive versus other offshore production and development assets in the world.
The operator of the Johan Sverdrup field, Statoil, has achieved a significant reduction in capital expenditures since the PDO was submitted for the Johan Sverdrup development. The initial budget for the full field development has been reduced from between NOK 170 and 220 billion (real), as of 2015, to between NOK 132 and 147 billion (nominal), all
numbers at project foreign exchange rate (6 NOK per USD). The costs for Phase 2 are estimated at between NOK 40 and 55 billion (nominal), a reduction of 50% compared to 2015 estimates, mainly as a result of project optimization. According to the operator, these improvements resulted in a Phase 1 break-even price of USD 20/boe and a full field break-even cost of USD 25/boe. The project is progressing without a single critical incident, on schedule and on budget.
The Company believes that its asset base is well balanced with producing assets, development projects, and discoveries. The Company believes that its asset base provides significant opportunities to organically grow its production and reserves. During the year ended December 31, 2016, excluding the impact of the reserves acquired in the BP acquisition, the Company achieved a reserve replacement rate of over 100%, driven in large part by discoveries in the North of Alvheim Area and the Askja/Krafla area with low finding costs. The Company's existing producing fields accounted for approximately 43% of its estimated 2P reserves as of December 31,2016.
All of the Company's producing, development and exploration assets are situated in Norway, an Organization for Economic Co-operation and Development ("OECD") country supported by a stable fiscal and regulatory regime which does not impose any local content requirements for oil and gas companies. The Company believes that its assets are in a proven hydrocarbon basin well understood by engineers and technicians. The geographic footprint of the Company's current operations in Norway is limited to shallow water (meaning operating environments of less than 500 meters) environments and largely centered around five areas in the North Sea and the Norwegian Sea, the prospective Utsira High area, the Alvheim area, the Valhall area and the Ula area, in the North Sea, and the Skarv area in the Norwegian Sea.
The Company aims to continue to increase reserves and resources from its existing producing assets by using established technologies to discover additional reserves and maximize recoveries of in-place hydrocarbons and managing natural decline rates. The Company has an ongoing drilling program to optimize resource recovery from producing reservoirs and to develop hydrocarbon accumulations close to existing infrastructure. For example, the Company has discovered hydrocarbons in the Filicudi and Garantiana prospects, close to the Gohta and Visund fields, respectively.
Most importantly, the Company has a track record of conducting its operations in a safe and environmentally responsible manner. The Company seeks to maintain high safety standards by implementing robust processes within its safety standards, processes and policies. The Company manages the security and emergency-preparedness measures at its facilities and are conducting regular training and exercises in order to manage potential incidents on its installations. The Company offers a professional health service to its staff that it believes is fully compliant with the current rules and regulations. In addition the Company has a close relationship with its main contractors in order to implement its HSE agenda and performance, and manage their verification programs. The Company works to integrate safety related goals, strategies and action plans in all projects and activities across its entire organization, and it prioritizes initiatives aimed at reducing the risk of major accidents at all levels within the Company. The Company has a fully integrated enterprise risk management system and-process across all assets and business functions. In addition, the Company is committed to minimizing its impact on the environment. For example, in 2016 the produced water discharge from its producing assets had an oil content of approximately 19.4 mg/l, significantly less than the required 30 mg/l.
The Company is focused on ensuring ample liquidity for the operation and continuing growth of its business. Aker BP has a BB+ long-term corporate credit rating from sap with stable outlook and a Ba2 corporate family rating with stable outlook from Moody's.
As of September 30, 2017, the Company had cash and cash equivalents of USD 81 million. Further it had committed undrawn credit facilities of USD 2.5 billion so that total cash and undrawn credit amounted to USD 2.6 billion. The Company has USD 4.0 billion in total commitments under a reserve-based lending facility with the ability to increase total commitments by an additional USD 1.0 billion (the "RBL Facility").
The borrowing base under the RBL Facility is set annually based on the Company's certified 2P reserves. As of September 30, 2017, the Company had drawn USD 1.46 billion of the USD 4.0 billion available under the RBL Facility.
The Company's financial profile is supported by the Norwegian fiscal regime, which allows exploration and production companies to effectively offset a nominal 89.7% of development costs and 78% of exploration costs and operational expenditure against their tax liabilities. As a result, the Company expects approximately 89% of its total capital expenditures to be offset against tax liabilities over the next six years. This tax treatment significantly de-risks the financing of its exploration and development program, cushions cost overruns and limits the impact on its cash flow of the pursuit of its long-term goal of expanding and replacing its reserves base.
The Company's asset base has been positive cash flow generative due to its significant existing oil and gas production and low production costs. In the first nine months of 2017, the Company generated USD 746 million in free cash flow and paid USD 187.5 million in dividends.
The Company benefits from a strong and supportive 40% equity owner in Aker ASA ("Aker ASA"), both from an industrial and financial perspective. Aker ASA is a large industrial investment company with a market capitalization of approximately NOK 28.2 billion as of 9 November 2017. As of December 31, 2016, approximately 65% of Aker ASA's investments related to the oil and gas industry. As an active owner, Aker ASA provides input and support to the Company's major business decisions through its representatives on its board of directors. Aker ASA has participated in full to maintain its ownership stake in all historical equity issues with the exception of the BP acquisition, in which Aker ASA agreed with BP to sell down its equity interest from 49.9% to 40%.
The Company further benefits from an additional strong and supportive 30% equity owner in BP. In connection with the BP acquisition, BP, through its subsidiary BP Global Investments Limited, became a significant equity owner in the Company. BP is one of the world's largest energy companies by market capitalization and has operations in over 70 countries. As part of the BP acquisition, two members of BP's senior management joined the Copmany's board of directors where they assist and support its operations and development with their knowledge and experience.
The Company's board of directors and senior management team members have an average of approximately 25 years of experience in the oil and gas industry, including substantial experience working on the NCS. The combined industry and regional expertise of the Company's board of directors and management team enables the Company to better understand and effectively manage the inherent risks associated with its business. The Company has established itself as a leading independent Norwegian oil and gas operator, initially through organic growth and more recently through two transformative acquisitions, the BP acquisition and the Marathon acquisition. The Company believes that the combination of the exploration, development and operational expertise and knowledge of the Aker BP team will prove valuable. The Company believes that its leadership team has the varied experience and proven track record in the oil and gas industry necessary to identify new production and development opportunities and to continue building a strong platform for the delivery of long-term growth.
The Company acquired a number of its key producing assets through the successful execution of a series of M&A transactions. For example, it acquired the Alvheim Area Fields in connection with the Marathon acquisition. More recently, the Company acquired the Skarv, Ula, Valhall, and Hod fields in connection with the BP acquisition. The Company has successfully integrated Marathon Norway and BP Norge into its existing corporate and operational structure. The Company believes its success is driven by its approach to integration, which is based on a merger strategy focused on developing shared values and vision. The Company focuses on fully integrating new employees within all levels of its existing organization and the Company adjust its governance structures to fit its post M&A scale.
The Company's past M&A transactions have improved its credit profile by, among other things, accelerating its free cash flow by providing additional upfront production and allowing the Company to better monetize its tax assets. The transactions have also allowed the Company to realize organizational and cost synergies, and strengthen its reserves base by adding optionality below historic cost. Both the Marathon acquisition and the BP acquisition were partially funded with new equity. Additionally, the Company's past M&A transactions have improved its credit profile by realizing organizational and cost synergies as well as by strengthening its reserves base and adding optionality at cost below historical cost.
The Company's strategic direction is built on three pillars: "Execute, improve, and grow safely."
The Company conducts all its operations in a safe and environmentally responsible manner.
The Company's existing producing asset base has delivered predictable returns over the last three years. Notably, the Alvheim Area Fields have consistently outperformed the Company's expectations and their decline rates have been actively managed. Average net production from such fields was 65,514 boepd, 58,555 boepd and 62,327 boepd for the years ended December 31, 2014, 2015 and 2016, respectively. The Company aims to continue to safely optimize returns from its existing producing assets by using established technologies to maximize recoveries of in-place hydrocarbons and managing natural decline rates by strategic infill drilling. The Company has an ongoing drilling program to optimize
recoveries from producing reservoirs and to develop hydrocarbon accumulations close to existing infrastructure. Further, the Company focuses on reliability and availability of key infrastructure to maintain production levels. The Company also intend to leverage the value of its existing infrastructure by developing new, smaller deposits in the vicinity of its existing platforms that would be uneconomic without the ability to utilize existing infrastructure.
The Company is working to execute projects efficiently and secure new high-quality development projects. The Company aims to develop opportunities below a breakeven price of USD 35 per boe at sanctioning. The Ivar Aasen Unit began production in December 2016 and was delivered on schedule and within budget. The Company is committed to maintaining the scheduling and budgetary discipline that it achieved with the Ivar Aasen Unit with its other development projects. In the near term, the Company is maturing several quality projects such as Ærfugl, Skogul (formerly "Storklakken") and Valhall West Flank.
The Company will continue its focus on delivering its main high-quality development asset, the Johan Sverdrup field. The Company believes the other participants in the field, including the operator, Statoil, share the same drive and commitment to delivering the Johan Sverdrup field on time and on or below budget. Statoil is an experienced development operator on the NCS with large personnel resources available. For a large development project like Johan Sverdrup, the field participants engage with the operator frequently through regular technical meetings (typically monthly or more often as needed), participant reviews and steering committee meetings (typically quarterly or more often as needed).
The Company aims to maintain a conservative financial profile and balance sheet with ample liquidity. The Company expects to fund exploration and development activities from a combination of production cash flows, proceeds of debt issuances and potentially proceeds of any portfolio management activities, such as farm-downs or sales. Any potential cost overruns in its exploration and development programs are partially mitigated by the favorable Norwegian tax regime, with refunds from the Norwegian state effectively covering 78% of exploration costs and a nominal 89.7% of relevant development cost.
The Company believes it prudently use debt financing and intend to maintain what it considers to be appropriate leverage levels. The Company closely monitors liquidity risk through cash flow forecasts and sensitivity analyses. The Company manages its credit risk by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness after transactions have been initiated. The Company maintains insurance that it believe is consistent with customary industry practices in the jurisdictions in which the Company does business and also procure business interruption insurance to protect against loss of production from its material assets, including but not limited to the Alvheim, Ivar Aasen, Skarv, Ula, and Valhall fields. The Company maintains a prudent risk management policy based on its continuous monitoring of market conditions. Exchange rate movements between the NOK and USD have favourably impacted the Company's NOK cost base, and therefore contributed to ongoing cost savings for the Company. The Company currently has a hedging program to reduce the risk connected to foreign exchange rates, interest rates and commodity prices. The Company also has in place put options with a strike price of USD 50 for 15% of estimated oil production for 2017, corresponding to approximately 50% of the after tax value. Further, the Company has embarked on its 2018 hedging program and it has currently bought put options with strike rates of USD 50 and USD 55 for around 14% of estimated 2018 oil production.
The Company works to create value and move opportunities faster by prioritizing flow, rather than resource, efficiency. Ongoing improvement initiatives and organizational efforts are grounded on "LEAN" principles, which include understanding value streams, visualizing progress and ensuring continuous learning. Successful implementation means improved quality and shorter lead times. The Company is working to systematically scrutinize the way it works to eliminate work that does not add value. Furthermore, the Company is currently establishing across the Company a culture in which employees are continuously searching for improvements.
The Company believes that it is possible to safely improve quality and reduce costs through reorganizing the value chain with strategic alliances and participations. For example, it entered into a subsea alliance (a combination of services and contracts with regards to underwater infrastructure) with Aker Solutions and Subsea 7 in the third quarter of 2016. Similarly, the Company has entered into a platform alliance with the intent to use a more integrated project delivery model in field development projects and it has entered into strategic framework agreements with key suppliers. The amount of data generated by industrial companies grows exponentially as they expand. At the same time, the world has abundant storage capacity and processing power. This enables solving complex, multi-dimensional problems with software that previously were analysed using such tools as two-dimensional spreadsheets or empirically derived experience. The Company aims to digitize field development and operation throughout the entire life cycle of a field, from exploration to abandonment.
The Company believes that it can prepare for changing market conditions by developing a flexible business model that anticipates growth and adapts to volatility. The Company believes that such a business model will allow it to identify and mitigate supply chain risks and to exploit market volatility to gain competitive advantages. For example, the Marathon acquisition and the BP acquisition have significantly strengthened the Company's operations and growth potential. The Company's low average production costs and break-even prices help to support its financial performance when faced with volatility in the oil and gas market.
Grow: Continue growing reserves by utilizing exploration skil/set and operational expertise and through strategic acquisitions
Portfolio management and enhancement are integral aspects of the Company's exploration, development and production strategy through which it seeks to realize value at an appropriate point in the life cycle of an asset. The Company will continue to review exploration opportunities on an ongoing basis and will continue to high grade its exploration portfolio to ensure it drills only those wells that it deem to offer an attractive risk/reward profile, and where possible, enable the Company to leverage its existing infrastructure position on the NCS.
The Company will maintain the structure of its successful exploration and development programs, which have resulted in its participation in such major discoveries as the Ivar Aasen and the Johan Sverdrup fields, and continue selective development and appraisal programs to combat natural decline and maintain existing reserves. The Company plans to continue focusing its exploration activities in Norway, where the favourable fiscal regime provides it with protection against price declines and reduces exploration and appraisal risk. In the year ended December 31, 2015, the Company acquired Svenska Petroleum Exploration AS and Premier Oil Norge AS which further strengthened its position in the Krafla/Askja, Garantiana, Frigg and Frøyareas on the NCS. In the year ended December 31,2016, the Company further strengthened its position on the NCS by acquiring Norwegian Energy Company ASA's Norwegian license portfolio, certain of Centrica Resources (Norge) AS' NCS license interests, certain NCS license interests from Tullow Oil Norge AS and further strengthening its position on the NCS through the BP Norge acquisition. The Company recently entered into an agreement to acquire Hess Norge to deepen its position in Valhall and Hod. The Company will focus on prospects with development potential in the short-term, which it believes it is well positioned to realize due to its extensive regional knowledge and experience on the NCS.
Leveraging this skillset is integral to the Company's strategy going forward of maintaining a strong exploration profile to protect its position as a major independent EftP company. The Company's exploration program is also positioned for future growth in both mature and frontier areas on the NCS across the North Sea, the Norwegian Sea and the Barents Sea. For example, the Company has encountered hydrocarbons at the Filicudi prospect in the Barents Sea and at the Langfjellet prospect in the North Sea. The Company intends to remain an active explorer and participant in future Norwegian APA and Norwegian License rounds, and will continue to develop the discoveries in its asset portfolio. For example, in January 2017, as part of the Norwegian APA license rounds, the Company obtained interests in 21 new production licenses (13 as operator). The Company further plans to actively explore and apply best practices learned from its current exploration and appraisal programs to future activities across the NCS. To complement its organic growth strategy, the Company may also consider selective strategic acquisitions of companies and/or interests in licenses with reserves or contingent resources. The Company evaluates acquisitions based on a set of criteria, including rate of return, field cash flow, operational efficiency, reserve life, development costs and decline profile, as well as quality of the organization. The Company also continuously seeks to optimize its asset portfolios by monetizing certain assets, through divestiture or farm down.
gradually build a fully fledged Norwegian E&P company on the NCS.
The Company is an E&P company with its business being the exploration, development and production of petroleum on the NCS. As outlined in more detail in Section 3.5 "License Portfolio, Reserves and Resources" below as of 30 September 2017 the Company had a license portfolio of 110 licenses of which the Company operates 64 licenses.
The Company's main income comes from the sale of petroleum products from producing fields on the NCS. The Company operates the Alvheim area (Alvheim, Bøyla, Volund and Vilje), the Ivar Aasen area, the Ula area (Ula and Tambar), the
Valhall area (Valhall and Hod) and the Skarv area. In 2016, the company had a liquids production of 23,830,388 boe and a gas production of 4,512,648 boe. In 2016, the Company's total petroleum revenue was USD 1,260,803,000, of which USD 1,120,094,000 was revenue from the sale of liquids and USD 128,436,000 was revenue from the sale of gas. In addition, USD 12,274,000 was tariff income. For the first nine months of 2017, total petroleum revenues amounted to USD 1,838,450,000.
The Company is also a partner (11.5733%) in the giant Statoil-operated Johan Sverdrup development. The development is progressing well and at the end of the third quarter 2017, approximately 70 percent of the Phase 1 facilities construction had been completed. First oil from Johan Sverdrup is anticipated in late 2019 and the field is expected to produce for 50 years.
As of 3 November 2017 the Company had a license portfolio of 110 licenses, 64 as operator and 46 as license partner as set out in the table below.
The Company is dependent on these licenses as they forms the basis for all of the Company's activities and income.
| Production Licenses (License Partner) | |
|---|---|
| --------------------------------------- | -- |
| Field | Company Participating Interest | Operator | Expiry |
|---|---|---|---|
| PL 006 C | 15.0% | Faroe Petroleum Norge AS | 31.12.2028 |
| PL 018 DS | 13.3% | Maersk Oil Norway AS | 31.12.2028 |
| PL 026 | 30.0% | Total EfrP Norge AS | 23.05.2025 |
| PL 029 B | 20.0% | Statoil Petroleum AS | 31.12.2032 |
| PL 035 | 50.0% | Statoil Petroleum AS | 14.11.2022 |
| PL 035 C | 50.0% | Statoil Petroleum AS | 14.11.2022 |
| PL 038 | 5.0% | Repsol Norge AS | 01.04.2021 |
| PL 048 D | 10.0% | Statoil Petroleum AS | 18.02.2018 |
| PL 102 C | 10.0% | Total EfrP Norge AS | 01.03.2025 |
| PL 102 D | 10.0% | Total EfrP Norge AS | 01.03.2025 |
| PL 102 F | 10.0% | Total EfrP Norge AS | 01.03.2025 |
| PL 102 G | 10.0% | Total EfrP Norge AS | 01.03.2025 |
| PL 265 | 20.0% | Statoil Petroleum AS | 27.01.2037 |
| PL 272 | 50.0% | Statoil Petroleum AS | 14.11.2022 |
| PL 405 | 15.0% | Centrica Resources (Norge) AS | 01.12.2036 |
| PL 457 BS | 40.0% | Wintershall Norge AS | 31.12.2036 |
| PL 492 | 60.0% | Lundin Norway AS | 28.02.2018 |
| PL 502 | 22.2% | Statoil Petroleum AS | 23.01.2018 |
| PL 507 | 45.0% | Statoil Petroleum AS | 23.01.2019 |
| PL 533 | 35.0% | Lundin Norway AS | 15.11.2017 |
| PL 554 | 30.0% | Total EfrP Norge AS | 19.02.2019 |
| PL 554B | 30.0% | Total EfrP Norge AS | 19.02.2019 |
| PL 554C | 30.0% | Total EfrP Norge AS | 19.02.2019 |
| PL 627 | 20.0% | Total EfrP Norge AS | 03.02.2021 |
| PL 627 B | 20.0% | Total EfrP Norge ASA | 03.02.2021 |
| PL 719 | 20.0% | Centrica Resources (Norge) AS | 21.06.2019 |
| PL 721 | 40.0% | DEA Norge AS | 21.06.2020 |
| PL 722 | 20.0% | Statoil Petroleum AS | 21.06.2019 |
| PL 778 | 20.0% | Lundin Norway AS | 06.11.2022 |
| PL 782 S | 20.0% | ConocoPhillips Skandinavia AS | 06.02.2023 |
| PL 782 SB | 20.0% | ConocoPhillips Skandinavia AS | 06.02.2023 |
| PL 782 SC | 20.0% | ConocoPhillips Skandinavia AS | 06.02.2023 |
| PL 811 | 20.0% | Centrica Resources (Norge) AS | 05.02.2024 |
| Total | 46 | |||
|---|---|---|---|---|
| PL 902 | 30.0% | Lundin Norway AS | 10.02.2025 | |
| PL 892 | 30.0% | AlS Norske Shell | 10.02.2026 | |
| PL 891 | 30.0% | ConocoPhillips Skandinavia AS | 10.02.2024 | |
| PL 871 | 20.0% | Wellesley Petroleum AS | 10.02.2024 | |
| PL 864 | 20.0% | Statoil Petroleum AS | 10.02.2025 | |
| PL 863 | 40.0% | AlS Norske Shell | 10.02.2025 | |
| PL 862 | 50.0% | AlS Norske Shell | 10.02.2026 | |
| PL 857 | 20.0% | Statoil Petroleum AS | 10.06.2020 | |
| PL 852 | 40.0% | (Norge) AS Centrica Resources |
10.06.2021 | |
| PL 844 | 20.0% | INEOS EEtP Norge AS | 05.02.2025 | |
| PL 842 | 30.0% | Capricorn Norge AS | 05.02.2023 | |
| PL 838 | 30.0% | PGNiG Upstream Norway AS |
05.02.2023 | |
| PL 813 | 3.3% | Statoil Petroleum AS |
05.02.2020 | |
PL 507 has been confirmed relinquished by the MPE, effective from 29 December 2017. An application for a license extension for PL 533 to 15 May 2019 has been sent to the MPE but no response has yet been received. PL 778 has been relinquished, but confirmation from the MPE has not yet been received.
Production Licenses (Operator)
| Field | Company Participating Interest | Expiry | |
|---|---|---|---|
| PL 001B | 35.0% | 31.12.2036 | |
| PL 006 B | 35.8% | 31.12.2028 | |
| PL 019 | 80.0% | 01.01.2029 | |
| PL 019 C | 80.0% | 01.09.2018 | |
| PL 026B | 90.0% | 23.05.2025 | |
| PL 027D | 100% | 01.03.2021 | |
| PL 028B | 35.0% | 31.12.2036 | |
| PL 033 | 37.5% | 31.12.2021 | |
| PL 033 B | 37.5% | 31.12.2028 | |
| PL 036C | 65% | 11.06.2021 | |
| PL 036D | 46.9% | 11.06.2021 | |
| PL 065 | 55.0% | 01.01.2022 | |
| PL 088 BS | 65% | 09.03.2022 | |
| PL 103 B | 70% | 01.03.2021 | |
| PL 150 | 65% | 08.07.2024 | |
| PL 150 B | 65% | 04.02.2018 | |
| PL 169 C | 50% | 01.03.2030 | |
| PL 203 | 65% | 02.02.2032 | |
| PL 203 B | 65% | 08.02.2019 | |
| PL 212 | 30.0% | 02.02.2033 | |
| PL 212 B | 30.0% | 02.02.2033 | |
| PL212 E | 30.0% | 02.02.2033 | |
| PL 242 | 35.0% | 04.06.2036 | |
| PL 261 | 50.0% | 12.05.2036 | |
| PL 262 | 30.0% | 02.02.2033 | |
| PL 300 | 55.0% | 12.12.2023 | |
| PL 340 | 65.0% | 17.12.2029 | |
| PL 340 BS | 65.0% | 17.12.2029 | |
| PL 364 | 90.3% | 06.01.2019 | |
| PL 442 | 90.3% | 15.06.2027 |
| Total | 64 | |
|---|---|---|
| PL 895 | 60.0% | 10.02.2024 |
| PL 893 | 60.0% | 10.02.2024 |
| PL 874 | 90.3% | 10.02.2024 |
| PL 873 | 40.0% | 10.02.2025 |
| PL 872 | 40.0% | 10.02.2024 |
| PL 869 | 40.0% | 10.02.2024 |
| PL 868 | 60.0% | 10.02.2024 |
| PL 867 | 40.0% | 10.02.2024 |
| PL 861 | 50.0% | 10.02.2024 |
| PL 858 | 40.0% | 10.06.2020 |
| PL 843 | 40.0% | 05.02.2025 |
| PL 839 | 23.8% | 05.02.2020 |
| PL 822 5 | 60.0% | 05.02.2023 |
| PL 821 B | 60.0% | 05.02.2023 |
| PL 821 | 60.0% | 05.02.2023 |
| PL 818 | 40.0% | 05.02.2023 |
| PL 814 | 40.0% | 05.02.2023 |
| PL 790 | 30.0% | 06.02.2022 |
| PL 784 | 40.0% | 06.02.2023 |
| PL 777 C | 40.0% | 05.02.2022 |
| PL 777 B | 40.0% | 06.02.2022 |
| PL 777 | 40.0% | 06.02.2022 |
| PL 762 | 20.0% | 07.02.2022 |
| PL 748 B | 50.0% | 07.02.2022 |
| PL 748 | 50.0% | 07.02.2022 |
| PL 724 B | 40.0% | 07.02.2021 |
| PL 724 | 40.0% | 07.02.2021 |
| PL 715 | 40.0% | 21.06.2019 |
| PL 677 | 60.0% | 08.08.2020 |
| PL 659 | 50.0% | 03.02.2021 |
| PL 626 | 50.0% | 03.02.2020 |
| PL 504 | 47.6% | 01.03.2021 |
| PL 460 | 65.0% | 01.03.2018 |
| PL 442 B | 90.3% | 15.06.2017 |
PL 150B has been relinquished, but confirmation from the MPE has not yet been received. An application for a license extension for PL 442B to 10 February 2027 has been sent, but no response has as yet been received from the MPE.
The Company retains AGR Petroleum Services AS ("AGR") for the purposes of certifying the reserves associated with its asset portfolio and internal reserve estimates. The Company's reserves are estimated and classified in accordance with the SPE's PRMS, which is consistent with the Oslo Stock Exchange's requirements for the disclosure of hydrocarbon reserves and contingent resources. The Company publishes an Annual Statement of Reserves in December of each year in accordance with these standards and requirements.
All volumes included in former Det norske portfolio within the reserve category (except for the minor Enoch and Atla) were certified by AGR in December 2016. These are the producing fields Alvheim (including Boa and Viper/Kobra), Vilje, Volund, Bøyla, lvar Aasen and the fields under development; Hanz, Gina Krag, Johan Sverdrup and Oda.
The year end 2016 reserve assessment for the former BP Norge fields, including Valhall, Hod, Ula, Tambar, Tambar East, Skarv and Ærfugl were certified by AGR in May / June 2017. Since the Company is now operator for and participant in the
portfolio of producing assets held by Hess Norge (Valhall and Hod), the AGR certification report for 2017 includes the portfolio of assets held by Hess Norge within the reserve category (Valhall and Hod). Thus, the change in the Company's reserve base in Valhall and Hod as a result of the Hess Norge transaction is an adjustment in the ownership interest in these two fields which have already been certified by AGR.
In 2016 and so far in 2017, the Company made discoveries both in the Barents Sea and in the North Sea and the Company has announced that these discoveries increased its resources above the target for the year. The majority of the increase in resources was due to the Filicudi (PL 533) discovery in the Barents Sea and the Askja (PL272) and Langfjellet (PL 442) discoveries in the North Sea. All three discoveries are assumed to have commercial potential. While no field development planning has yet commenced for Filicudi, both the Askja and Langfjellet discoveries are included in the NOAKA field development plan.
With the discoveries in the Company's current asset portfolio, it is expected that commercial activity will have duration past the year 2050.
In 2016 the Company has participated in fifteen (15) exploration and appraisal wells and have proved hydrocarbons in nine (9) wells. Below is an overview of the Company's exploration activity in 2016 and so far in 2017:
| Company | Drilling | |||||
|---|---|---|---|---|---|---|
| License | Prospect/Field | Interest | operator | Type of well | Area | Result |
| 2016 | ||||||
| PL 554 | Garantiana | 30 % | Total E&P Norge | Wildcat | North Sea | Dry |
| PL 035 | Madam Felle | 50 % | Statoil | Wildcat | North Sea | Oil |
| Petroleum AS | ||||||
| PL 035 | Viti | 50 % | Statoil | Wildcat | North Sea | Dry |
| Petroleum AS | ||||||
| PL 001 B | Ivar Aasen | 34.8 % | Aker BP | Wildcat | North Sea | Oil/Gas |
| PL 035 | Askja SE | 50 % | Statoil | Wildcat | North Sea | Oil |
| Petroleum AS | ||||||
| PL 001 B | Ivar Aasen | 34.8 % | Aker BP | Appraisal | North Sea | Dry |
| PL 035 | Askja SE | 50 % | Statoil | Appraisal | North Sea | Dry |
| downflank | Petroleum AS | |||||
| PL 272 | Beerenberg | 50 % | Statoil | Wildcat | North Sea | Gas / |
| Petroleum AS | Condensate | |||||
| PL 272 | Slemmestad | 50 % | Statoil | Wildcat | North Sea | Gas / |
| Petroleum AS | Condensate | |||||
| discovery | ||||||
| PL 272 | Haraldsplass | 50% | Statoil | Wildcat | North Sea | Gas / |
| Petroleum AS | Condensate | |||||
| PL 626 | Rovarkula | 50% | Aker BP | Wildcat | North Sea | Dry |
| PL442 | Langfjellet | 90.3 % | Aker BP | Wildcat | North Sea | Oil |
| PL442 | Langfjellet | 90.3% | Aker BP | Appraisal | North Sea | Oil |
| PL442 | Langfjellet | 90.3% | Aker BP | Appraisal | North Sea | Dry |
| PL442 | Langfjellet | 90.3% | Aker BP | Appraisal | North Sea | Oil |
| 2017 | |||||||
|---|---|---|---|---|---|---|---|
| PL 522 | Filicudi | 35% | Lundin Norway | Wildcat | Barents Sea | Oil/ Gas | |
| AS | |||||||
| Johan Sverdrup | Tonjer | 11.6% | Statoil | Appraisal | North Sea | Oil | |
| Unit | Petroleum AS | ||||||
| PL 533 | Filicudi | 35% | Lundin Norway | Appraisal | Barents Sea | Oil/ Gas | |
| AS | |||||||
| PL 492 | Gohta | 60% | Lundin Norway | Appraisal | Barents Sea | Dry | |
| AS | |||||||
| PL 150B | Volund West | 65% | Aker BP | Wildcat | North Sea | Dry | |
| PL 677 | Hyrokkin | 60% | Aker BP | Wildcat | North Sea | Dry |
|---|---|---|---|---|---|---|
| PL 442 | Nordfjellet | 90.3% | Aker BP | Wildcat | North Sea | Dry |
| PL 442 | Delta | 90.3% | Aker BP | Appraisal | North Sea | Oil |
| PL 533 | Hufsa | 35% | Lundin Norway AS |
Wildcat | Barents Sea | Ongoing |
Since the formation of Aker BP through the merger of ex Det norske oljeselskap ASA and BP Norge AS in 2016, the Company has not entered into any material contracts outside the ordinary course of business, other than the transaction agreement and related entered into for the purpose of the Transaction, see Section 4 "The Transaction", and the transaction agreements for the Company's other recent acquisitions referred to in Section 3.1 "-Introduction".
In January 2017, Aker BP announced its operational targets for the year 2017. After the first three quarters of 2017, the Company is on track to achieve these targets. Production is now expected to be between 137,500 and 140,000 barrels oil equivalents (boe) per day, compared to an initial estimate of 128,000 to 135,000 boe per day. The main reason for the strong performance has been better than expected production at the Alvheim field. Operating costs are expected to be around USD 10 per boe, compared to an initial expectation of USD 11 per boe, largely as a function of the increased production volume. The expectations for capital and exploration expenditures remain unchanged at USD 900-950 million and USD 280-300 million respectively, while the expectation for decommissioning costs has been lowered from USD 100- 110 million to USD 80-90 million, mainly due to changes in the schedule of the planned activities.
The Company's investment projects have been progressing according to plan, including the Statoil-operated Johan Sverdrup field development where the gross cost estimate for phase 1 has been reduced from NOK 97 billion to NOK 92 billion during 2017 (i.e more than NOK 30 billion reduction from NOK 123 billion at PDO in 2015), all numbers at project foreign exchange rate (6 NOK per USD). Aker BP remains on track to submit Plans for Development and Operations (PDO) for three new development projects before the end of 2017. This involves the Ærfugl project (tieback to Skarv), the Valhall Flank West project (tieback to Valhall) and the Skogul project (tieback to Alvheim).
The Company's principal sources of liquidity are operating cash flows from its producing assets. To the extent necessary, the Company is also able to utilize the undrawn capacity under its financing facilities to fund its liquidity needs. In addition to its operating cash flows, the Company relies on the debt capital markets for both short and long term funding. Currently, the Company has access to one syndicated bank facility maturing over the next four years. Further, the Company has two outstanding bond issuances, maturing in three and five years respectively. Additionally, the Company has received an indicative offer from a consortium of five banks for a bank facility intended for financing the acquisition of Hess Norge. The Company's liquidity needs consist of funding operating expenses, changes in working capital, capital expenditures, debt service requirements and other liquidity requirements that may arise from time to time, including, without limitation, (i) refinancing of outstanding debt, (ii) acquisitions and other investment opportunities, (iii) exploration and development capital expenditure and (iv) payments in the ordinary course of business.
The Company prepares short-term (12 months) and-long term forecasts on a regular basis in order to plan the Company's liquidity requirements. These plans are updated regularly for various scenarios and form part of the decision basis for the Company's Board of Directors.
Some reporting requirements are also required under the Company's bank facilities, including quarterly updates of a revolving liquidity budget for the next 12 months and throughout the bank facility's maturity.
As of 30 September 2017, the Company had cash reserves of USD 81 million and undrawn facilities of USD 2,540 million.
See Section 8.6 "Other Selected Financial Information" for certain relevant ratios and other unaudited non-l FRS key financial and operating information for the Company.
The Company actively monitors its financial risks with the objective of protecting the Company's business operations from adverse movements in such risks. The Company has in place policies for this management. Key risks and considerations are outlined below:
Most of the Company's revenue is received in USD, GBP and EUR, whilst it has expenditures in other currencies, predominantly in NOK. The Company manages this exposure through derivatives such as FX forwards and FX options.
Fluctuations in commodity prices, in particular Brent crude oil, affect the revenue of the Company. Whilst the Company has no mandatory hedging requirements, the Company manages this exposure through derivatives from time to time. The Company currently has put options with a strike price of USD 50/bbl for approximately 15% of estimated 2017 oil production as well as put options with a minimum strike price of USD 50/bbl for approximately 14% of estimated 2018 oil production (before considering any additional production from the Transaction). In 2016, the Company had put options in place with a strike price of USD 55/bbl for around 20% of the estimated 2016 oil production (prior to inclusion of the production from the BP Norge assets).
The Company is exposed to changes in the USD (LIBOR) and NOK (NIBOR) interest rates on its floating rate debt. Currently the Company has fixed the LlBOR interest rate for USD 400 million of its floating rate debt until the end of 2020. Further the Company's outstanding NOK Senior Unsecured Bond has been swapped into USD using a cross currency interest rate swap.
The Company's goal is to be fully funded for all its committed work program, both operational and development activities. For this, the Company aims to maintain a diversified funding base for its short . and long term financing requirements. In addition to its equity funding, the Company currently has in place a credit facility with a bank syndicate and it has issued two bonds in the debt capital markets. The maturities of its debt facilities are staggered over the next three to five years. The Company's current credit facilities and bonds are further described in detail below.
On 8 July 2014, the Company entered into a USD 3 billion senior secured rnulti-currency revolving credit facility, subsequently increased to USD 4 billion following the merger with BP Norge in 2016. The facility was further amended in August 2017 in order to achieve a better capital structure for the Company subsequent to the merger with BP Norge.
Amounts available under the RBL facility are subject to a borrowing base limitation, set annually based on the Company's 2P reserves. As of 30 September 2017, the available amount under the RBL was USD 4.0 billion, of which the Company has drawn USD 1.46 billion. The facility may be used for general corporate purposes.
The interest payable is LlBOR plus a margin of 2 - 3% per annum, based on drawn amounts. Certain fees are also payable, including, but not limited to: (i) a commitment fee on available commitments; and (ii) a commission on letters of credit issued.
The RBL facility is currently secured by security interests over certain of the assets, including, but not limited to certain participating interests in licenses of the Company for the development and production of oil and gas resources on the NCS.
The agreement contains provisions regarding events of default, as well as customary representations and warranties, subject to certain agreed exceptions and qualifications. Furthermore, the Company must ensure compliance with certain financial covenants to be calculated and satisfied in accordance with the terms therein, including, but not limited to:
In July 2013, the Company issued a NOK 1.9 billion unsecured bond loan with Nordic Trustee ASA as trustee. The loan carries interest at a rate equal to three month NIBOR plus 6.5% per annum. For the calculation of interest, NIBOR shall, if NIBOR falls below 1%, be deemed to equal 1%. The principal falls due on 2 July 2020 and interest is paid on a quarterly basis.
The proceeds of the NOK 1.9 billion bond issuance were used for general corporate purposes. On 1 April 2015, on 27 May 2016 and subsequently on 13 October 2016, bondholder meetings were held in order to approve certain amendments to the bond agreement.
The NOK Bond agreement does not permit the Company to prepay the NOK Bond prior to maturity date. The bond is however repayable at the bondholder's request, at levels between 101% - 107%, upon the occurrence of certain change of control events or in the event that the Company issues certain forms restricted debts as defined in the loan agreement.
The agreement contains provisions regarding events of default, as well as customary representations and warranties, subject to certain agreed exceptions and qualifications. Further, the Company must ensure compliance with certain financial covenants to be calculated and satisfied in accordance with the terms therein, including, but not limited to:
In July 2017, the Company issued an unsecured bond loan to Nordic, US and international investors. The initial bond issue was USD 400 million, but the documentation allows the Company to increase the bond through subsequent issuances. The loan carries fixed interest at a rate equal to 6% per annum. The principal falls due on 1 July 2022 and interest is paid on a semi-annual basis. The proceeds of the bond loan were used for general corporate purposes and to redeem the Company's previously outstanding USD 300 million subordinated bond.
The bond agreement contains redemption options to the issuer, including, but not limited to, voluntary redemption after two years, starting at 103% of principal and declining throughout the remaining life of the loan. The bonds are repayable at the bondholders' request, at 101% of par value with the addition of accrued interest, upon certain events constituting a change of control. The agreement contains provisions regarding events of default, as well as customary representations and warranties, subject to certain agreed exceptions and qualifications. The agreement does not contain any financial covenants.
The table below shows the contractual maturities of financial liabilities of the Group as of 30 September 2017.
| USD thousands | Original Loan | Outstanding | Payments Due in Period | |||
|---|---|---|---|---|---|---|
| Loan | Amount | Principal | 2017 | 2018 | 2019 | 2020- |
| RBL • | 4,000,000 | 1,460,000 | O | O | O | 4,000,000 |
| NOK Senior Unsecured | ||||||
| Bond | 255,000(1) | 255,000 | O | O | O | 255,000 |
| US High Yield Bond | 400,000 | 400,000 | O | O | O | 400,000 |
| Total | 4,655,000 | 2,115,000 | O | O | O | 4,655,000 |
(1) The NOK Senior Unsecured Bond has been swapped into USD using a cross currency interest rate swap. This amount reflects this swap.
Each of the Company's financing facilities may be used for general corporate purposes.
Further, the financing facilities contain certain restrictions on the level of investments, which can be made outside the NCS.
Subject to the closing of the Transaction, the Company will enter into a \$1.5 billion bank facility, with a consortium of five banks, to finance the Transaction. Such new bank financing will allow the Company to maintain its financial capacity under its existing RBL Facility and to finance the acquisition at a lower cost than is otherwise available under its existing RBL Facility. The bank facility is expected to carry an interest of LlBOR plus a margin of 1.50 to 2.00%, and will be secured by a pledge over the shares of Hess Norge. The maturity date of the bank facility is expected to be 18 months from the date of completion of the Transaction. The bank facility is subject to documentation and contemporaneous completion of the Transaction. The bank facility will mature on the earlier of 18 months from the closing of the Hess transaction and the refunding of the tax loss carry-forward that the Company will assume as part of the Transaction.
Other than as discussed above, there has been no significant change in the Group's financial and trading position since 30 September 2017.
As of the date of this Information Memorandum, the Company is of the opinion that the working capital of the Group is sufficient for its present requirements.
As of the date of this Information Memorandum, the Company is not subject to any governmental, legal or arbitration proceedings during the course of the preceding twelve months, including any such proceedings which are pending or threatened, of such importance that they have had in the recent past, or may have, a significant effect on the Company or the Group's financial position or profitability.
The Company's Articles of Association provide that the Board of Directors shall have up to eleven members. In accordance with Norwegian law, the employees are entitled to elect up to one third, and at least two, of the members of the Board of Directors. The other directors are appointed by the Company's corporate assembly. In accordance with Norwegian law, the CEO and at least half of the members of the Board of Directors must either be resident in Norway, or be citizens of and resident in an EU/EEA country.
The members of the Board of Directors and their holdings of shares in the Company as of the date of this Information Memorandum are presented in the table below.
| Position | Shares | |
|---|---|---|
| Øyvind Eriksen | Chairman | |
| Anne Marie Cannon | Deputy Chair | 6.308 |
| Kjelllnge Røkke | Director | |
| Gro G. Kielland | Director | |
| Trond Brandsrud | Director | |
| Katherine Anne Thomson | Director | |
| Bernard Looney | Director | |
| Terje Solheim | Director | 1.906 |
| Lone Olstad | Director | |
| Bjørn Thore Ribesen | Director | 22.747 |
| Ørjan Holstad | Director | 1.062 |
| Murray Auchincloss | Deputy Director |
The composition of the Company's Board of Directors is currently in compliance with the independence requirements of the Norwegian Code of Practice for Corporate Governance of 30 October 2014 (the "Corporate Governance Code"). The Corporate Governance Code provides that a board member is generally considered to be independent when he or she does not have any personal, material business or other contacts that may influence the decisions he or she makes as a board member.
Among the shareholder-elected board members, two (Øyvind Eriksen who is the CEO of Aker ASA, and Kjell Inge Røkke) are affiliated with the Company's largest shareholder Aker Capital AS and further two board members (Bernard Looney and Katherine Anne Thomson) are affiliated with the Company's second largest shareholder BP Global Investment Limited. Deputy Chair Anne Marie Cannon was elected member of the Board of Directors for Aker ASA in April 2015. All other board members are considered independent of the Company's main shareholder, as well as of the Company's material business contacts. All board members are considered independent of the Company's executive personnel.
The Company's executive management (the "Management") consists of ten individuals. The members of the Company's Management and their holdings of Shares in the Company as of the date of this Information Memorandum are set out in the table below.
| Position | Shares | |
|---|---|---|
| Karl Johnny Hersvik | CEO | 1.416 |
| Alexander Krane | CFO | 16.248 |
|---|---|---|
| Olav Henriksen | SVP Projects | |
| Øyvind Bratsberg | Special Advisor | 53.848 |
| Eldar Larsen | SVP Operations | 1.416 |
| Gro G. Haatvedt | SVP Exploration | 10.832 |
| Per Harald Kongelf | SVP Improvement | |
| Tommy Sigmundstad | SVP Drilling and Well | |
| Jorunn Kvåle | SVP HSE | |
| Ole-Johan Molvig | SVP Reservoir | 3.894 |
None of the members of the Board of Directors have contracts providing benefits upon termination of their positions as Board Members.
The members of the Management have contracts with six months' notice period upon termination of contract. The CEO has a contract which entitles him to six months' notice period plus a six months' severance pay upon termination of contract.
Our articles of association provide for a Nomination Committee composed of a minimum of three members who are elected by the general meeting. The Nomination Committee is responsible for nominating the members of the Board of Directors, the Corporate Assembly and the Nomination Committee. The Nomination Committee of Aker BP is comprised of the following members: Arild Støren Frick (Chairman), Finn Haugan and Hilde Myrberg. At the annual general meeting of Aker BP in 2016, Finn Haugan and Hilde Myrberg were re-elected as members of the Nomination Committee for two years. At the annual general meeting of Aker BP in 2017, Arild Støren Frick was re-elected as Chairman of the Nomination Committee for two years.
The Company has an Audit and Risk Committee, which is comprised of the following members: Trond Brandsrud (Chairman), Anne Marie Cannon and Kathrine Anne Thomson, all members of the Board of Directors. The primary purposes of the Audit and Risk Committee are to:
The Audit and Risk Committee reports and makes recommendations to the Board of Directors, but the Board of Directors retains responsibility for implementing such recommendations. The Chair of the Audit and Risk Committee, Trond Brandsrud, is considered to have experience and formal background qualifying as "financial expert" according to the requirement stated in the Public Limited Liability Company Act.
The Company has an Organizational Development and Compensation Committee, which is comprised of the following members: Øyvind Eriksen, Gro Kielland and Terje Solheim. The Organizational Development and Compensation Committee is established to ensure that remuneration arrangements support the strategy of the business and enable the recruitment, succession planning and leadership development, and motivation and retention of senior executives while complying with the requirements of regulatory and governance bodies, satisfying the expectations of shareholders and remaining consistent with the expectations of the wider employee population.
The Company's corporate governance principles are based on, and comply with, the Corporate Governance Code other than as disclosed in the Company's corporate governance statement for the year ended 31 December 2016 set forth in the Company's 2016 Annual Report which is incorporated by reference in this Information Memorandum; see Section 11 "Incorporation by Reference; Documents on Display".
The Company's registered business address, Akerkvartalet, Oksenøyveien 10, 1366 Bærum, Norway, serves as c/o address for the members of the Board of Directors, Management and the other Supervisory Bodies in relation to their functions in the Company.
Aker BP ASA is a Norwegian public limited liability company incorporated under the laws of Norway and in accordance with the Norwegian Public Limited Companies Act of 13 June 1997 no. 45 with company registration number 989 795 848. The Company was incorporated on 9 May 2006.
The Company has its head office and registered address at Oksenøyveien 10, 1366 Lysaker, Norway, its telephone number is +47 51 353000, and its website is www.akerbp.com.
As of 30 September 2017, the Company does not have any material subsidiaries. BP Norge AS was liquidated in the third quarter in 2017 following the transfer of its activity to the Company in Q4 2016. The Company currently has three subsidiaries, Alvheim AS, Aker BP AS (previously Marathon Oil Norge AS) and Sandvika Fjellstue AS, which are immaterial for consolidation purposes and which will therefore not be described in detail in this Information Memorandum.
The Company's governance structure is set out in the diagram below.
The shares of the Company is admitted to trading on the Oslo Stock Exchange and trade under the trading symbol "AKERBP".
The Company's Shares are registered in book-entry form with the VPS under the International Securities Identification Number ("ISIN") N00010345853. The Company's register of shareholders with the VPS is administrated by DNB Bank ASA, Registrars Department, Dronning Eufemias gate 30, N-0191 Oslo, Norway.
As of the date hereof, the Company's share capital is NOK 360,113,509 divided into 360,113,509 shares with each share having a par value of NOK 1.00. All the existing Shares have been created under the Norwegian Public Limited Companies Acts, and are validly issued and fully paid. The Company has one class of shares.
On 22 November 2017, the Company carried out a share capital increase following a private placement on October 31, 2017. The share capital was increased by NOK 22,376,438 from NOK 337,737,071 to NOK 360,113,509 by issue of 22,376,438 new shares, each with a par value of NOK 1.00. The subscription price for the share issue was NOK 184 per share, consisting of a subscription price of NOK 182.5 per share and NOK 1.5 per share as payment for the associated right to cash dividend of USD 0.185 per share.
On 30 September 2016, the Company carried out a share capital increase in connection with the BP Norge acquisition. The share capital increased from NOK 202,618,602 to NOK 337, 737,071 by issuing 135,118,469 new shares, each with a par value of NOK 1.00.
On 5 August 2014, the Company carried out a share capital increase under a rights issue (Norwegian: fortrinnsrettsemisjon) whereby the share capital was increased by NOK 61,911,239, from NOK 140,707,363 to NOK 202,618,602, by issue of 61,911,239 new shares, each with a par value of NOK 1.00. The subscription price in the rights issue was NOK 48.50 per share.
As of 22 November 2017, which was the latest practicable date prior to the date of this Information Memorandum, and insofar as known to the Company, the following persons had, directly or indirectly, interest in 5% or more of the issued share capital of the Company (which constitutes a notifiable holding under the Norwegian Securities Trading Act):
| Number of Shares | Holding (%) | |
|---|---|---|
| Aker Capital AS. | 144.049.005 | 40% |
| BP Global Investments Limited | 108.021.449 | 30% |
Following completion of the Transaction, Aker Capital AS will be the owner of 144,049,005 shares (constituting approximately 40% of the Company's share capital at such time), and BP Global Investments Limited will own a total of 108,021,449 shares (constituting approximately 30% of the Company's share capital at such time). Other shareholders will hold a total of 108,043,055 shares representing approximately 30% of the Company's share capital.
The Company's independent auditor is KPMG AS, which has its registered address at Sørkedalsveien 6, 0369 Oslo, Norway and has audited the Company's separate and consolidated financial statements as of 31 December 2014, 2015 and 2016 and for each of the years then ended which are prepared in accordance with IFRS and are incorporated by reference in this Information Memorandum. The partners of KPMG AS are members of The Norwegian Institute of Public Accountants (Nw. Den Norske Revisorforening).
With respect to the unaudited pro forma financial information included in this Information Memorandum, KPMG AS has applied assurance procedures in accordance with ISAE 3240 Assurance Engagement to Report on Compilation of Pro Forma Financial Information Included in a Prospectus in order to express an opinion as to whether the unaudited pro forma financial information has been properly compiled on the basis stated, and that such basis is consistent with the accounting policies of the Company.
Advokatfirmaet BA-HR DA, Tjuvholmen alle 16, 0252, Oslo, Norway has acted as legal counsel (as to Norwegian law) to the Company in connection with the Transaction.
This Section provides information on the background and reasons for the Transaction as well as a discussion of certain reLated arrangements and agreements entered into or to be entered into in conjunction with the Transaction.
Through the Transaction the Company will acquire 100% of the shares in Hess Norge, against a cash consideration of USD 2 billion. Hess Norge is today a wholly owned subsidiary of Hess Norway Investments Limited, and holds all of the Hess group's interests in exploration and production licenses on the NCS. Hess has been involved in the Norwegian oil and gas sector since activity began in 1965. The transaction includes all of Hess Norge's interests on the Norwegian Continental Shelf comprising a 64.166666% participating interest in PL 006B, a 62.5% participating interest in PL 033B, a 62.5% participating interest in PL 033, and a 15% participating interest in PL 220, as well as an associated 64.04688% interest in the Valhall Unit. Aker BP is seeking to sell a share of the participating interest in the Valhall and Hod fields. Aker BP will also assume Hess Norge's tax positions, which include a tax loss carry forward with a net nominal after-tax value of USD 1.5 billion, as booked in Hess Norge's 2016 annual accounts. The cash consideration of USD 2 billion will on closing be adjusted for working capital and net debt as per the Effective Date of the Transaction and include certain agreed adjustments for corporate cash flow for the period from Effective Date until completion of the Transaction. The economic effective date of the Transaction is 1 January 2017, and Aker BP acquires cash flow from the producing assets as from the Effective Date.
By purchasing the shares in Hess Norge, the Company will strengthen its position on the Norwegian Continental Shelf. Both production and reserves will increase significantly. The Transaction is another move as a part of the Company's ambition to grow and be the leading independent offshore E&P company. As the operator of the Valhall and Hod fields, the Company knows the area very well and sees a great value creation potential through increased oil recovery and flank developments. The Company wilt seek to sell a share of the participating interest in the fields to partners who want to work together with Aker BP to proactively target the upside potential in the area.
The Seller is a wholly owned subsidiary within the Hess group. The shares of the parent company Hess Corporation are listed on the New York Stock Exchange.
The Company will acquire 100% of the shares in Hess Norge against a cash consideration payable upon closing of the Transaction. The economic effective date of the transaction will be 1 January 2017, and closing is expected by the end of 2017.
Through the transaction, Aker BP will strengthen its production and resource base. Aker BP will also assume Hess Norge's tax positions, which include a tax loss carry forward with a net nominal after-tax value of USD 1.5 billion, as booked in Hess Norge's 2016 annual accounts.
Included in the transaction are proven and probable (2P) reserves of 150 million barrels of oil equivalent (mmboe) and best estimate 2C contingent resources of 195 mmboe, based on Aker BP's own assessment per year-end 2016, of which 87 per cent is liquids. For the nine months ended September 30, 2017, Hess Norge net production averaged 23.8 Mboed, compared to 27.9 Mboed for the year ended December 31, 2016.
In connection with the SPA, a decommissioning security agreement was entered into between the Seller and the Company to provide for certain decommissioning security provisions with regard to Hess Norge's interests. The Company has agreed on certain conditions to provide Seller security in respect of the payment of certain of the Seller's decommissioning obligations arising in relation to Hess Norge's licence interests in the form of a letter of credit or a parent company guarantee.
Following the Transaction, an asset transaction will take place, in which the Company will acquire the assets in Hess Norge except for tax losses carried forward and any unused uplift, subject to approvals from MPE and MoF.
The board of directors in Hess Norge currently consists of 6 members. Johan Nicolai Vold currently serves as chairman. The other board members are Anders Glensvig Nymann, Brian David Truelove, Martin George Edwards, Helena Kathryn Dilys Deal and Geurt Gerhard Schoonman. Martin George Edwards is the Managing Director of Hess Norge.
According to the 2016 NGAAP Financial Statements, the total revenues for Hess Norge were NOK 3 565 million and the net operating result was a loss of NOK 1 290 million. Total balance sheet assets were NOK thousand 35 273 million (all of the foregoing in rounded numbers, for further accounting information see Section 10 "Selected financial information for Hess Norge AS").
Hess Norge has no external financial debt other than working capital. All internal intercompany debt will be assigned to Aker BP upon closing of the Transaction.
The cash consideration will be financed through the issuance of USD 500 million in new equity as well as a syndicated loan facility as described in paragraph 3.8 (Sources of liquidity). The issue price for the new equity was determined through a book building process. Aker ASA ("Aker") and BP plc ("BP") subscribed for 40 per cent and 30 per cent of the shares issued, respectively, at NOK 182.5 per share. The new equity was issued in a private placement on October 31, 2017 that resulted in gross proceeds of NOK 4,084 million (approximately USD 500 million) through a share capital increase. The private placement and issuance of new shares was completed on 22 November 2017, following a general meeting that was held 21 November 2017. The Company will finance the cash consideration for the Transaction through a S 1.5 billion bank facility.
The Transaction is subject to customary conditions precedent to closing, including approvals from the MPE and the MoF, which approvals may be subject to conditions (See 1. 1 Risks Relating to the Transaction- The Company will most likely be required to divest a share of the acquired assets, and may not be able to conduct such a divestment at terms similar to, or better than, those of the Transaction). In connection with the completion of the Transaction, the Company is required to provide a parent company guarantee of associated decommissioning obligations to the Norwegian state (on the standard form of parent guarantee pursuant to the Norwegian Petroleum Act).
Closing of the Transaction is expected in the end of fourth quarter of 2017, subject to regulatory approval.
There are no special agreements or arrangements with the members of the board of directors or the management in connection with the Transaction.
The business of Hess Norge and the Company is expected to be combined into one single legal entity with tax effect from 1 January 2017 and thereby be consolidated for tax purposes. Hess Norge will likely apply for a tax refund for tax losses carried forward and any unused uplift as of the Effective Date.
Each of the Company and the Sellers will bear their own expenses in connection with the Transaction.
The Transaction will further strengthen the Company's position as a leading player on the NCS, with significant operatorships, current production and strong operating cash flow. The Company will have a strong balance sheet, which is expected to enable the Company to increase dividend payments from the fourth quarter 2017 and position it for further growth, assuming the Company's current market outlook and subject to risk factors.
This Section provides an overview of the business of Hess Norge as of the date of this Information Memorandum. The following discussion contains Forward-looking Statements that reflect the Company's plans and estimates; see "Cautionary Note Regarding Forward-Looking Statements" on page 1. You should read this Section in conjunction with the other parts of this Information Memorandum, in particular Section 1 "Risk Factors" and Section 6 'The Company Following completion of the Transaction".
Hess Norge is a Norwegian private limited liability company incorporated under the laws of Norway and in accordance with the Norwegian Private Limited Liability Companies Act of 13 June 1997 no. 45 with company registration number 930 459 321, The company was incorporated on 8 August 1973.
Hess Norge has its head office and registered address at Jåttåvågveien 7, 4020 Stavanger, Norway and its website is www.hessnorge.no, with telephone number +4751 31 5400.
The origins of Hess Norge began with Amerada that was a licensee in Norway from 1965 and later became Amerada Hess post the Amerada Hess merger in 1969. The company later changed name to Hess Norge in 2006. Amerada applied for blocks in the first licensing round on the NCS and was awarded license 006, blocks 215 and 218 that later became the Valhall field. The company currently holds 4 production licenses, none as operator. Three of the production licenses are producing fields.
As per the 2016 Hess Norge NGAAP Financial Statement, petroleum income amounted to NOK 3,564 million, operating cash flow amounted NOK -747 million with net income for the year NOK -1,290 million. The total assets on the balance sheet amounted to NOK 35,273 million and equity amounted to NOK 2,215 million. There are no significant assets or liabilities not on the balance sheet. FY16 production was net 27.9 mboed and YTD Sept 2017 production was net 23.8 mboed.
During the normal course of business, Hess Norge will be involved in tax disputes with the Oil Taxation Office, and Hess Norge has made accruals for probable liabilities related to ongoing tax disputes based on Hess Norge's most recent evaluation and tax assessment.
Hess Norge operates from its office in Stavanger. As of June, the company employed 20 employees, all local onshore staff.
The board of directors in Hess Norge currently consists of 6 members. Johan Nicolai VoId currently serves as chairman. The other board members are Anders Glensvig Nymann, Brian David Truelove, Martin George Edwards, Helena Kathryn Dilys Deal and Geurt Gerhard Schoonman. Martin George Edwards is the Managing Director of Hess Norge.
Hess Norge is currently participating in two producing fields, Valhall, Hod, as well as production license PL 220.
The Valhall field lies in Blocks 218 and 2/11, the Hod field lies in Block 2111 and PL 220 lies in Block 6710/10.
The Valhall area consists of the producing fields Valhall and Hod. Production started in 1982 and following commissioning of the new PH platform in 2013 the field now has the potential to continue producing for several decades. In early January 2017, Valhall and Hod passed one billion barrels of oil equivalents produced, which is more than three times the volume expected at the opening of the field in 1982. The ambition is to produce a further 500 million barrels. Valhall consists of a field centre with six platforms and two unmanned flank platforms. The field is located in 70 metres of water. Hod is tied back and remotely operated from Valhall. The Valhall Flank developments are two identical unmanned wellhead platforms each equipped with 16 drilling slots and located about 6 km (one to the North and one to the South) from the existing Valhall Facilities where well streams are processed. The South Flank started production in 2003 and the North Flank came on stream in 2004. Liquids are routed via pipeline to Ekofisk and further to Teesside in the UK. Gas is sent via Norpipe to Emden in Germany.
The Valhall Flank West project is planned to be developed out of the Tor Formation at the western flank of the Valhall field. Valhall is a chalk type reservoir located in the southern area of the Norwegian North Sea. The project passed concept selection in April 2017, and is currently in the FEED phase and experiencing a seamless transition into detail engineering. The plan is to submit a PDO before the end of 2017.
The Valhall Flank North platform is located to the north of the Valhall complex in 72 meter water depth. A project is currently being matured to expand capability for water injection to the northern basin drainage area, thus securing the Valhall base production through enabling water injection to existing depleted producers and offering a potential for increased reserves recovery from Valhall of 6-8 mmboe gross.
Hess Norge's license portfolio is included in table below:
| License | Field/prospect | Interest | Operator | Expiry | Phase |
|---|---|---|---|---|---|
| 006 B | Valhall | 64.16667% | Aker BP ASA | 31.12.2028 | Production |
| 033 | Hod | 62.5% | Aker BP ASA | 31.12.2021 | Production ext. |
| 033 B | Valhall | 62.5% | Aker BP ASA | 31.12.2028 | Production |
| 220 | 15.0% | Statoil Petroleum AS |
02.02.2024 | Initial ext. |
Hess Norge has not entered into any material contracts outside the ordinary course of business for the two years immediately preceding the date of this Information Memorandum, and Hess Norge has not entered into any contracts containing obligations or entitlements that are, or may be, material to the issuer as of the date of this Information Memorandum.
For the nine months ended September 30, 2017, Hess Norge net production averaged 23.8 Mboed, compared to 27.9 Mboed for the year ended December 31, 2016. The decrease is due to decline in current production and no new wells put into production on Valhall until August 2016. Year to date (September 2017) cash costs have averaged USD 23.4 boe versus USD 25.3 boe for 2016 full year. The decrease is primarily a result of the businesses simplification and efficiency (S&E) benefits being delivered. Year to date (September 2017) decommissioning costs are USD 80 million versus 127 million for 2016 full year. The Maersk Invincible rig is performing plugging and abandonment of old wells at Valhall. Year to date (September 2017) capital expenditure is USD 79 million versus USD 13 million for 2016 full year. During 2017 a 7 well drilling campaign has started at ValhalliP.
There has been no significant changes in the financial and trading position in Hess Norge, other than a capital increase of NOK 10.6 billion (USD 1.35 billion) in October 2017 by converting debt to equity.
As of the date of this Information Memorandum, Hess Norge has not been involved in any governmental, legal or arbitration proceedings during the course of the preceding twelve months, including any such proceedings which are pending or threatened, of such importance that they have had in the recent past, or may have, a significant effect on the Company or the Group's financial position or profitability after the Transaction.
This Section provides information about the prospects of the results of the Transaction and its expected implications on the Company following the Transaction and should be read in conjunction with other parts of the Information Memorandum, in particular Section 5 "Presentation of Hess Norge" and Section 9 "Pro Forma Financial Information". The following discussion contains Forward-looking Statements that reflect the Company's plans and estimates. Factors that could cause or contribute to differences to these Forward-looking Statements include, but are not limited to, those discussed in Section 1 "Risk Factors" and the "Cautionary Note Regarding Forward-Looking Statements" on page 1.
Following completion of the Transaction, the Company will hold a portfolio of 110 licenses, of which 64 are operated. The total net proved plus probable reserves (PSO/2P) for the combined company are estimated at 861 million boe as of 1 January 2017.
The Company will still be the operator of ten producing fields including Alvheim, Ivar Aasen, Bøyla, Volund, Vilje, Ula, Tambar, Valhall, Hod, and Skarv. The Company plans to sell a share of participating interest in the Valhall and Hod fields.
The Company will have a balanced portfolio of operated assets and a high quality inventory of non-sanctioned projects and discoveries, with potential to reach production in excess of 300,000 boepd in 2023.
The strengths and strategies of the Company will not materially change as a result the completion of the Transaction. The main assets acquired in the Transaction are already operated by the Company, and the Transaction will deepen the Company's exposure to those assets. The Transaction is not deemed to have any material effect on the Company's culture, as the number of employees acquired are limited.
The Company sees great value creation potential in the Valhall and Hod assets, and intends to develop the assets with the sanctioning of new projects that will increase production in the area. The Company intends to apply its operational strategies to improve operations and ensure efficient field developments through alliance models. In the planned divestment, the Company aims to identify new partners that will support the Company's plans for the development of the fields.
The Company will continue to be a fully-fledged oil company with activities within exploration, development and production. The Company will have a resource base and organisation as a sizeable player. The development of the Johan Sverdrup field will further grow the Company's production volumes. The Company will strengthen the position as the largest independent oil and gas company on the NCS in terms of activity and production.
This Section discusses the industry and markets in which the Company operates. Certain of the information in this Section relating to market environment, market developments, growth rates, market trends, industry trends, competition and similar information are estimates based on data compiled by professional organisations, consultants and analysts in addition to market data from other external and publicly available sources, and the Company's knowledge of the markets. There are different views related to market developments reflecting the overall uncertainties. Any forecast information and other Forward-looking Statements in this Section are not guarantees of future outcomes and these future outcomes could differ materially from current expectations. Numerous factors could cause or contribute to such differences, see Section 1 "Risk Factors" for further details.
Global economic activity is picking up with a cyclical recovery in investment, manufacturing, and trade. According to the International Monetary Fund, global growth is expected to rise from 3.1% in 2016 to 3.5% in 2017 and 3.6% in 2018. Stronger activity and expectations of more robust global demand, coupled with some agreed restrictions on oil supply, have helped commodity prices recover from their lows in early 2016. As a result, higher commodity prices have provided some relief to commodity exports and helped lift global headline inflation and reduce deflationary pressures. Financial markets remain strong driven by expected continued policy support in China and fiscal expansion and deregulation in the United States. If confidence and market sentiment remain strong, the International Monetary fund estimates that shortterm growth could indeed surprise on the upside. However, structural problems, such as low productivity growth and high income inequality, are likely to persist. Inward-looking policies, including protectionism, threaten global economic integration and the cooperative global economic order, which have served the world economy, in particular emerging markets, well. A reversal in market sentiment and confidence could tighten financial conditions and exacerbate existing vulnerabilities in a number of emerging market economies, including China, which faces the daunting challenge of
reducing its reliance on credit growth. A dilution of financial regulation may lead to stronger near-term growth but may imperil global financial stability and raise the risk of costly financial crises down the road. In addition, the threat of deepening geopolitical tensions persists, especially in the Middle East and North Africa. Source: International Monetary Fund, "World Economic Outlook," April 2017 Update.
According to the Organization of the Petroleum Exporting Countries ("OPEC"), world oil demand growth in 2016 was broadly unchanged at 1.38 mb/d which resulted in an average of 95.05 mb/d. For 2017, OPEC expects oil demand growth to be around 1.27 mb/d to average 96.32 mb/d. Demand growth is being led by India and China but also OECD Americas. Source: OPEC Monthly Oil Market Report-April 2017. In the longer term, the U.S. Energy Information Administration ("EIA") estimates that much of the growth in world liquid fuels consumption is projected for the emerging economies of Asia, the Middle East and Africa, where strong economic growth and rising populations increase the demand for these fuels. In contrast, demand for liquid fuels in the United States, OECD Europe, and other regions with well-established liquids markets is projected to grow slowly or decline. Source: U.S. Energy Information Administration, "International Energy Outlook 2017", September 2017
Source: U.S. Energy Information Administration, "International Energy Outlook," 2017
With regards to petroleum and other liquid fuels, consumption is expected to grow from 95 million barrels per day (mb/d) in 2015 to 100 mb/d in 2020 and to 113 mb/d in 2040. Most of the growth in liquid fuels consumption will be in the transportation and industrial sectors. In the transportation sector, in particular, liquid fuels will continue to provide most of the energy consumed. Although advances in nonliquid-based transportation technologies are anticipated, they are not enough to offset the rising demand for transportation services worldwide. EIA anticipates liquid fuel consumed for transportation will increase by 0.7% a year from 2015 to 2040, and the transportation sector accounts for 56% of the total increase in delivered liquid fuels use. The remaining increase in liquid fuels consumption is attributed to the chemicals industry. Economic growth-as measured in gross domestic product (GDP)-is a key determinant in the growth of energy demand. The world's GDP (expressed in purchasing power parity terms) is predicted to rise by 3.0% per year from 2012 to 2040. The fastest rates of growth are projected for the emerging, non-OECD countries, where combined GDP increases by 3.8% per year. In OECD countries, GDP grows at a much slower rate of 1.7% per year over the projection as a result of their more mature economies and slow or declining population growth trends. The strong projected economic growth rates in the non-OECD drive the fast-paced growth in future energy consumption among those nations. Source: U.S. Energy Information Administration, "International Energy Outlook 2017", September 2017
According to OPEC, supply from non-OPEC producers in 2016 was revised marginally lower due to a downward adjustment in Russian oil supply in the fourth quarter of 2016 to now show a contraction of 0.71 mb/d to average 57.3 mb/d. The forecast for 2017 was revised up by 0.37 mb/d to show growth of 0.95 mb/d, following upward adjustments in all quarters, mostly in the U.S., to average 58.3 mb/d. The revisions were driven by actual production data for February 2017, as well as higher expectations for the remainder of the year. OPEC NGLs and non-conventional oil production in 2017 was revised up by 40 tb/d to average 6.22 mb/d, representing growth of 0.17 mb/d. In April, OPEC production decreased by 18 tb/ d, according to secondary sources, to average 31.73 mb/ d. Source: OPEC Monthly Oil Market Report-May 2017.
In the medium term, the effect of lower oil prices on non-OPEC supply still creates uncertainties in the overall outlook. According to OPEC, due to the faster than expected response of tight oil to price changes, supply from the U.S. exhibits the highest annual growth over the medium-term but also the largest contraction in 2016.
OPEC met on May 25, 2017 and announced an extension to voluntary production cuts through to the end of the first quarter of 2018, originally set to end in June 2017. Of the non-OPEC countries that participated in the initial production cut, only Russia formally agreed to remain party to the extended cuts. As a result of the announcement, EIA forecasts OPEC crude oil production will average 32.3 mb/d in 2017 and 32.8 mb/d in 2018. EIA forecasts a decline in global petroleum and liquid fuel inventories by about 0.2 mb/din 2017, followed by an increase by an average of 0.1 mb/din 2018. Despite OPEC's decision to voluntarily cut production, the effect on the pace of global liquid fuels inventory draws has been partially offset by production growth in other countries. OPEC forecasts that non-OPEC supply is expected to increase in 2017 by 0.95 mb/d. U.S. crude oil production surpassed 9 mb/d in February 2017 and is expected to increase by 0.82 mb/d over the year. The 2018 forecast of 10 mb/d exceeds the previous record level of 9.6 mb/d set in 1970. In addition to growth in the U.S., higher oil production is expected in Canada (0.22 mb/d) and Brazil (0.21 mb/d). A large part of the excess supply overhang contained in floating storage has been reduced and the improvement in the world economy should help support oil demand. Sources: EIA Short- Term Energy Outlook-June 2017, OPEC Monthly Oil Market Report-May 2017
As of early November 2017, the Brent crude oil price has reached a level or around USD 60 per barrel, following a recovery since January 2016 when the price hit a 12 -year low of around USD 28 per barrel. The historical price record occurred in July 2008 with a price at USD 146.1 per barrel. These movements illustrate the cyclicality of the oil market. High oil prices tend to drive increased investments in new production capacity, which in turn tends to lead to oversupply and lower prices. Correspondingly, low oil prices tend to lead to reduced investments, leading to reduced oil supply and hence an upward pressure in the oil price.
The figure below illustrates Brent crude oil price for the last ten years.
The oil price is affected by a number of factors, including, but not limited to, changes in supply and demand, OPEC regulations, weather conditions, regulations from domestic and foreign authorities, political and economic conditions and the price of substitutes.
It should be noted that the oil market is dynamic and that the demand for oil to some extent is inversely linked to the price. Longer periods of high oil prices can therefore lead to increased use of alternative energy sources at the cost of oil demand.
According to lEA's World Energy Investment 2017, global upstream oil and gas investments will rebound modestly in 2017, after a 44% plunge between 2014 and 2016. A 53% upswing in US shale investment and resilient spending in large producing regions like the Middle East and Russia looks to drive upstream investment to bounce back by 3% in 2017 (a 6% increase in nominal terms). Spending is also rising in Mexico following a very successful offshore bid round in 2017.
There are diverging trends for upstream capital costs: at a global level, costs are expected to decline for a third consecutive year in 2017, driven mainly by deflation in the offshore sector, although with only 3% decline the pace of the plunge has slowed down significantly compared to 2015 and 2016. The rapid ramp up of US shale activities triggers an increase of costs of 16% in 2017 after having almost halved in 2015·16.
The oil and gas industry is undertaking a major transformation in the way it operates, with an increased focus on activities delivering paybacks in a shorter period of time and the sanctioning of simplified and streamlined projects. The global cost curve has rebased, and the significant component of cost reduction experienced over the last two years is likely to persist in the foreseeable future. Source: World Energy Investment 2017, lEA.
The NCS is the continental shelf over which Norway exercises sovereign rights as defined by the United Nations Convention on the Law of the Sea and the Norwegian Petroleum Act. Its major parts are the shelves of the North Sea, Norwegian Sea and Barents Sea.
The area of the shelf is four times the area of Norway mainland and constitutes about one-third of the Europe continental shelf, and in 2016, Norway was the world's third largest gas exporter and the 11th largest oil exporter.
Today, the petroleum industry is the largest industry in Norway measured in value creation, state revenues and export value. Since production started, the industry has contributed approximately NOK 13,000 billion to the Norwegian GDP measured in year 2016 value. The industry has therefore been a cornerstone for building the Norwegian welfare state and the Norwegian economy in general. The Norwegian State has decided that all petroleum operations must benefit society as a whole to the greatest extent possible. This is the primary reason why the State claims a large share of the value creation through taxes, fees and the State's Direct Financial Interest (SDFl). These revenues are currently being invested in the Government Pension Fund Global, which at the end of 2016 was valued at approximately NOK 7,510 billion.
Below is an overview of the status of the different areas on the NeS.
Source: Norwegian Petroleum Directorate (NPD), www.npd.no
The discovery and subsequent development of Ekofisk in 1969 marked the beginning of oil exploration and production on the NeS. Although most of the NeS has reached its mature phase, there are still large reserves in the province remaining to be found or produced. At the end of 2016, reserves amounted to 3,009 million Sm3 of oil equivalent, according to the MPE. Of this, the gas reserves constitute 60%. Gross reserves, or the licensees' estimates before production is deducted, increased by 113 million Sm3 of oil equivalent. Production in 2016 was 233 million Sm3 of oil equivalent. The change in the accounts shows an annual production of 232 million Sm3 of oil equivalent. The reason for this is that a fixed conversion factor is used when NGL is converted to Sm3 of oil equivalent. This resulted in a reduction in the reserves of 119 million Sm3 of oil equivalent, or about 4%, in 2016. Source: "Resource accounts for the Norwegian shelf per 31.12.2016" (April 2017) - Website of the Ministry of Petroleum and Energy and the Norwegian and Petroleum Di rectorate (www.norskpetroleum.no )
Source: "Resource accounts for the Norwegian shelf per 31.12.2016" (April 2017)-Website of the Ministry of Petroleum and Energy and the Norwegian and Petroleum Directorate (www.norskpetroleum.no)
The oil production from existing fields on the NCS peaked in year 2000 at 181.2 million 5m3. Oil production in 2016 was 94.0 million 5m3 (1.62 million bbls per day), compared with 91.0 million 5m3 (1.57 billion bbls per day) in the previous year. 80 fields contributed to the total oil production in 2016.
Continued investments in the drilling of new development wells and other measures to improve recovery are important for the oil production on the NCS.
In 2016, 116.6 billion 5m3 of saleable natural gas was produced on the NCS. This was marginally lower than the year before, when production reached a new record level of 117.2 billion 5m3. The NPD expects gas output from existing fields to increase somewhat during the next five years.
In 2016, 20.2 million 5m3 (0.35 million boepd) of NGL and 1.9 million 5m3 (0.03 million boepd) of condensate was produced on the NCS.
Below is an overview of the production development from 1971 and forecast to 2020, where 15m3 = 6.29 barrels.
Source: Norwegian Petroleum Directorate (NPD), www.npd.no
In order to increase the production and tap the resource potential on the NeS, the oil industry has to increase its exploration efforts. The number of wildcats (oil wells in an unexplored area) and appraisal wells being drilled on the NeS reached a historically low level in 2005, and started to increase thereafter, helped by the Norwegian government's ambition to increase drilling on the NeS. The number of spudded exploration wells reached a record high of 65 wells in 2009. Following the drop in commodity prices during the second half of 2014, the industry has reduced spending on exploration activities. In 2016, 28 wildcats and 8 appraisal wells were commenced. The development in exploration activity is illustrated in the figure below.
The figure below shows the number of wildcat wells and appraisal wells 1970 - 2016.
Source: Norwegian Petroleum Directorate (NPD), www.npd.no
Production from existing oil fields on the NCS is declining, and a step-up in exploration activity combined with increased production from existing fields is needed to reach government stated production goals. Among the measures taken to stimulate increased exploration are (i) a more flexible and effective exploration policy (i.e. increasing acreage available for exploration and increasing the number of licenses awarded), (ii) increasing the number of companies on the NCS, and (iii) tax incentives to encourage companies to increase the exploration activity. These measures are briefly described in the following sections.
A first measure taken by the government to increase the activity on the NCS was to increase the acreage available for exploration, both in mature and immature areas. To increase the activity in mature areas the Norwegian government started to award new production licenses annually in 2003, the APA. Since the first APA round in 2003, the APA acreage has been expanded several times. In the APA 2016 the government awarded 56 licenses, while the numbers were 56, 54, 65,51,60,49,38,35 and 52 in APA15, APA14, APA13, APA12, APA11, APA10, APA09, APA08 and APA07, respectively.
In 2015, the government for the first time since 2004 opened up new acreage announcing the 23rd licencing round. The 23rd licensing round opened up 34 blocks in the formerly disputed area towards Russia in the south-eastern Barents Sea, 20 blocks in other parts of the Barents Sea and three blocks in the Norwegian Sea. In 2016, the government awarded ten new licenses consisting of 40 blocks in total in this area.
In addition to increasing the acreage available for exploration, the Norwegian government also expressed its desire to increase the number of companies on the NCS. The Norwegian government acknowledged that the interest among many of the established players for mature areas on the NCS is moderate, and have stressed the importance of new and creative solutions to increase the production on the NCS. The criteria for award of licenses in APAs and Licensing Rounds are factors like technical quality of the application, demonstrated quality of the company and the proposed work program. There is no upfront payment for the production licenses, however, a fee of NOK 123,000 applies for the handling of the license application, which is awarded by the MPE based on a full technical evaluation by the NPD. The MPE is required to make its decision on the basis of objective, non-discriminatory and published criteria. The authorities have a strong focus on attracting technically competent companies that can contribute to the development of the NCS and have therefore introduced a prequalification system. All new oil companies have to be prequalified by the authorities before they can be awarded or acquire interests in production licenses. This system ensures that only companies with proper and relevant competence and systems in place, as well as necessary financial resources, are approved as licensees on the NCS. According to NPD, 27 companies are currently listed as operators on the NCS, while a further 17 are listed as partners in production licenses.
Companies not in a tax paying position may annually claim a refund from the State of the tax value of direct and indirect cost, except financial charges, incurred in exploration for petroleum resources. The tax value is set to the total of direct and indirect costs multiplied by the tax rate, currently 78 per cent. The refund will reduce the tax loss carry forward correspondingly. The amount of exploration cost may not exceed the annual net loss from the petroleum activities of the taxpayer, to ensure that the costs are not already set off against taxable income.
There are still large areas of the NCS that the Norwegian Parliament has not yet opened for petroleum activities. This applies to the area surrounding Bjørnøya in the Barents Sea, the north-eastern Norwegian Sea, Skagerrak and the areas surrounding Jan Mayen. The general rule for unopened areas is that the Norwegian Parliament must resolve to open an area for petroleum activities before a licensing round can be announced. The basis for such decisions must include preparation of an impact assessment to consider factors such as economic and social effects, as well as environmental effects the activities could have for other industries and the surrounding district.
The main regulatory authorities governing the petroleum industry on the NCS are the Norwegian Parliament, the MPE, the Norwegian Petroleum Directorate ("NPD"), the Petroleum Safety Authority ("PSA"), the Ministry of Labour ("MoL"), the MoF, the Oil Taxation Office ("OTO") and the Norwegian Environmental Agency ("NEA").
The ultimate regulatory authority rests with Parliament. The MPE is responsible for ensuring that the petroleum activities are carried out in accordance with the regulatory framework laid down by Parliament. Subordinated to the MPE is the NPD whose activities relate to resource management and day-ta-day issues. The PSA regulates the technical and operational safety of the operations and the MoL regulates the working environment. The MoF is responsible for the policies and legislation regarding the taxation in the petroleum industry whilst the OTa conducts the annual tax assessments. Finally, NEA has regulatory responsibility for pollution caused by petroleum activities on the NCS.
The Petroleum Act provides the legal framework for the proprietary rights to subsea deposits as well as the licensing system. section 1-1 of the Petroleum Act states that the proprietary rights to subsea petroleum deposits is vested in the Norwegian State. It also governs the award of production licenses as well as governing the exploration, development, production and transportation of petroleum on the NCS.
The Norwegian State is the largest participant on the NCS, with their shareholding in Statoil Petroleum AS and through the State's direct participation in various exploration and production licenses through the Direct Financial Interest, managed by Petora AS, a State-owned company.
The 1975 Act Relating to the Taxation of Subsea Petroleum Deposits provides the legal basis for the taxation of petroleum activities on the NCS.
There are two systems for awarding production licenses on the NCS: (i) the ordinary numbered concession rounds; and (ii) the APA.
The ordinary numbered concession rounds are normally held every two years and these cover new acreage on the NCS. In 2003 the State introduced an APA award system where mature areas on the NCS, normally close to existing or planned infrastructure, are released for applicants. In order to be eligible to apply in either the numbered concession rounds or the APA rounds a company that is not already an established license holder on the NCS needs to pre-qualify as a potential licensee on the NCS. This pre-qualification process means that a company must meet certain criteria regarding their organisation, qualifications of staff and their financial strength among other things. An additional and more rigorous prequalification process is required of any company which is not already an operator which wants to become an operator on the NCS. Companies can apply for production licenses either on their own or as part of a group where one company applies as the operator and the rest as licensees. The application must be submitted within a set deadline along with an application fee of NOK 123.000 (application fee for the APA 2017 application) for the cost of handling the applications.
The MPE assesses the applications and will have the ultimate saying in which companies, or groups of companies, are awarded which licenses. One of the most important factors for the MPEs assessment of the applications is the extent to which a given company, or a group of companies, is willing to commit to a firm work program. Where a group of companies is awarded a license, the MPE will appoint one of the companies as the operator of the license, i.e. the company responsible for the joint activities of the license group.
The MPE will often require a parent company guarantee, in a form specified by the MPE, from the parent companies of applicants for the fulfilment of the obligations set out in the license as well as the potential liability towards the State. The license group must be in a position to cover the capital expenditure costs of the work obligations set out in the production license.
A production license is awarded for an initial period of up to ten (10) years and sets out work obligations, which must be completed within this initial period. When such work obligations have been fulfilled, the licensees have the option to apply for the term of the license to be extended for a period of up to thirty (30) years, however the area covered by the license will at this point be reduced. The MPE has recently, in mature acreage on the NCS, required that license groups make a drill or drop decision for whether to drill an exploration well and retain the license or to drop the license within a relatively short time-frame (e.g, two (2) years). Once a production license enters into the extended period, an area fee will become applicable. The area fee is set by the NPD and is calculated on a square kilometre basis with increasing area fees applying for the first, second and any subsequent years. The current area fee rates are NOK 34.000 per km2 for the first year, NOK 68.000 per km2 for the second year and NOK 137.000 per km2 for each subsequent year. The general area fees are no longer applicable if an area becomes covered by a PDO.
For production licenses awarded pursuant to the 9 April 1965 NO.4 Decree the license holder shall pay a flat rate fee of NOK 40.000/km2 annually not depending on the exploration status of the area. On 18 October 2017 the NPD submitted a proposal for adjustments to the area fee rate for licenses awarded pursuant to the 1965 Decree. The proposed new rate is expected to increase from NOK 40.000/km2 to 49.000/km2 from 1 January 2018. The license holders of licenses awarded pursuant to the 1965 Decree may however, by application, with final effect decide that the general rules for the area fee shall apply to the production license.
Licensees must enter into an agreement for the petroleum activities as a condition of being awarded a license. Such agreements regulate the voting rights within the license group as well as appending the JOA and the accounting agreement, both of which are standard form agreements on the NCS. The JOA regulates the relationship between the licensees. It forms the basis for the operation of the activities in the license, including setting out the operators' duties, the mechanism for allocation of costs and the decision-making processes within the license group. The license group must establish a management committee representing all licensees, which acts as the highest ranked decision-making body in the joint venture. All petroleum produced in a license is allocated to each licensee, and the operator, in accordance with their participating interest share in the license.
Where petroleum deposit(s) stretch over two or more licenses, the relevant licenses will need to enter into a unitisation agreement which regulated the licensees' rights to the petroleum deposit(s). Such unitisation agreement in effect replaces the underlying JOA and accounting agreements for the licenses with respect to the subject deposit(s) that stretches over more than one production licenses. The unitisation agreement will determine how much of the total petroleum deposit will be allocated to each license. An initial distribution may be subject to a redetermination at a later stage.
Where licensees wish to transfer part or all of their participating interest in a license, such a transfer is subject to MPE approval and a tax clearance from the MoF, although the principle of tax neutrality is often applied meaning that any gain by the seller is not taxable and any cost for the purchaser is not tax deductible. A transfer of a controlling interest in a company, which holds participating interests in production licenses are also subject to MPE approval.
Operators on the NCS have an obligation to obtain permits from the PSA and the NPD in advance of commencing any drilling operations. Drilling exploration wells (to and in oil-bearing strata) are permitted solely pursuant to production licenses, not exploration licenses. A separate consent from the PSA and NPD is required for each exploration well. The operator must submit detailed information with regard to both the technical and environmental aspects of the planned operation when submitting such an application. Comprehensive HSE procedures must also be in place, including the establishment of emergency preparedness procedures. The operator will also need to obtain permits to discharge to sea and air from the Norwegian Pollution Control Authority and this is a part of the consent to drill.
In order to develop a petroleum deposit, the operator must prepare a PDO which needs to be approved by the MPE. A PDO must set out the development solution, estimated development costs, production profile for the deposit as well as information regarding decommissioning. It will also need to include information on facilities for utilisation and transportation of petroleum.
The JOA states that the management committee in the license joint venture must decide on whether to submit a PDO to the MPE for approval. Where the estimated investment is more than NOK 10 billion the PDO will also be presented to Parliament. Each licensee must individually accede to the PDO by giving notice of such to the MPE. If a licensee does not accede to a PDO, the licensees that have acceded the plan may carry out the project on their own ("sole risk"). The licensee not acceding to the PDO will retain its rights in the license acreage outside the deposit, which is subject to the PDO.
In order to construct and operate facilities for the transportation and utilisation of petroleum (e.g. pipelines and processing facilities) a Plan for Installation and Operation ("PlO") must be submitted to the MPE for approval, where such facilities are not already included in an approved PDO.
MPE often decides that owners of transportation and processing facilities must allow third parties to have access to such facilities. The MPE can impose a solution on parties who are unable to agree on shared use of such facilities.
Gassled, the joint venture established on 1 January 2003 is the formal owner of the Norwegian gas transportation infrastructure as well as the receiving terminals in the UK and on the European continent. These facilities are subject to a general principle of third party access.
The NPD issues annual production permits based on the PDO taking into consideration proper resource management ensuring the maximum depletion of petroleum from the reservoirs. These permits allow the operator to produce defined volumes of petroleum on behalf of their license groups. As mentioned above, the license groups also require consent to use facilities and installations as well as permits for discharges and emissions to sea and air.
Liability for pollution damage. Chapter 7 of the Petroleum Act stipulates a strict liability for pollution damage on all the licensees. In other words, a licensee is liable for pollution damage without regard to fault. However, if it is demonstrated that an inevitable event of nature, act of war, exercise of public authority or a similar force majeure event has contributed to a considerable degree to the damage or its extent under circumstances which are beyond the control of the liable party, the liability may be reduced to the extent it is reasonable, with particular consideration to the scope of the activity, the situation of the party that has sustained damage and the opportunity for taking out insurance on both sides.
A claim against the license holders for compensation relating to pollution damage shall initially be directed to the operator. If any part of the compensation is left unpaid on the due date by the operator, this part shall be covered by the licensees in accordance with their participating interest in the license. If any of the licensees fails to cover their share, the liability relating to this share shall be allocated proportionately between the others licensees.
Emissions and discharges from Norwegian petroleum activities are regulated by several acts, including the Petroleum Act, the C02 Tax Act, the Sales Tax Act, the Greenhouse Gas Emission Trading Act and the Pollution Control Act. Discharge of oil and chemicals in relation to exploration, development and production of oil and natural gas are regulated under the Pollution Control Act (the "Pollution Act"). In accordance with the provisions of the Pollution Act, the operator must apply for a discharge permit from relevant authorities on behalf of the license group in order to discharge any pollutants into the sea. Further, the Petroleum Act states that burning gas in flares beyond what is necessary to ensure normal operations is not permitted without approval from the MPE.
All operators on the NSC have an obligation to establish sufficient procedures for the monitoring and reporting of any discharge into the sea. The Climate and Pollution Agency, the Norwegian Petroleum Directorate and the Norwegian Oil Industry Association have established a joint database for reporting emissions to air and discharges to sea from the petroleum activities, "Environmental Web" (EW). All operators on the NCS report emission and discharge data directly into the database.
The licensees are required to submit to the MPE a plan for decommissioning and cessation of the petroleum activities. The MPE then decides, based on the plan, on the disposal of the facilities. The decommissioning costs are carried by the licensees, and are petroleum tax deductible for current licensees. Following transfer, cf. below, of a license share, a company will remain liable on a secondary pro rata basis for decommissioning cost if its successor defaults on its obligations to pay such cost. Such secondary liability is on after tax terms, meaning that the company being held liable on a secondary pro rata basis will not get a tax deduction.
For companies participating in production and transportation of petroleum products on the NCS, there are two, partially overlapping income tax regimes: ordinary income tax imposed by the general rules in the Norwegian General Tax Act of 1999 (the "GTA") and the special petroleum tax on income imposed by the Petroleum Tax Act (the "PTA"). As a result, the total marginal income tax rate for companies engaged in E&P activities on the NCS is 78 per cent, consisting of a 24 per cent general income tax (probably 23 in 2018) and a 54 per cent special petroleum tax to the State levied on income generated by exploitation, treatment or transportation of petroleum, ref. the PTA section 5. The petroleum tax applies on a corporation net profit level, not on a ring-fenced basis. Losses generated by other activities may as a general rule not be set off against assessed income for special tax (54 per cent) purposes and there are limitations on the right to set of other losses against the general tax base (24 per cent).
Taxable income is computed according to the general tax legislation and particular rules set out in the PTA. Gross income generated by oil sales is assessed according to a norm price system, whereby the sales prices are fixed by an administrative body with the objective of arriving at fair market prices. Income generated by gas sales is, with very few exceptions, assessed on actual sales prices.
Although certain important deductible expenses are dealt with in the PTA, the deductibility of expenses for purposes of the special petroleum tax is based on the general rules in the GT A. The timing of deductions for tax purposes generally follows the realisation principle, i.e. when the expense is unconditionally incurred by the taxpayer. Provisions in the accounts based on prudent accounting principles are generally not deductible for tax purposes.
Financial items, such as interest income and expenses and currency losses and gains etc. are taxable. However, interest expenses and foreign currency items relating to interest-bearing debt instruments are treated separately from other financial items. Such costs fall within the offshore tax regime, meaning that they are deductible against income taxed at 78 per cent. However, the amount of such costs deductible against income falling within the offshore tax regime is capped as follows:
Offshore tax deduction = (Interest cost + exchange gainl loss) x 50% x Tax value offshore assets 31.12 Average interest-bearing debt
Any such costs in excess of this cap together with other financial items fall within the ordinary corporate tax regime, meaning that they are deductible against income taxed at 24 per cent. If the taxpayer does not have any income which is taxed under the ordinary corporate tax regime from which the excess costs can be deducted, it may deduct an amount from its offshore income but only so as to give it an effective deduction against 24 per cent tax, and not against 78 per cent tax.
For general income tax purposes, depreciation deductions are permitted under a reducing balance system. For petroleum tax purposes depreciations of production installations and offshore pipelines are permitted under a straight-line basis at a rate of 16 2/3 per cent annually from the year in which the investments takes place, i.e. a deprecation over 6 years. In addition to the depreciation allowance offered, an uplift of 5.4 per cent pr. year (probably 5.3 per cent in 2018) is granted in the special tax basis for a four-year period for investments in production and pipeline facilities.
Hence, a licensee on the NCS that is subject to Norwegian taxation will be entitled to tax deductions with regard to exploration and production costs (running expenses, net financial items, depreciations and uplift) and transportation costs (tariff payments). Losses for tax purposes may be carried forward indefinitely. Interest is added for losses incurred in 2002 and subsequent years. The calculated interest is added to loss carry forward at the end of each year.
Companies not in a tax position may annually claim a refund from the State of the tax value of direct and indirect costs, except financial charges, incurred in exploration for petroleum resources. The tax value is set to the total of direct and indirect exploration costs (except financial charges) multiplied by the tax rate, currently 78 per cent. The refund will reduce the tax loss carry forward correspondingly. The amount of exploration costs may not exceed the annual net loss from the petroleum activities of the taxpayer, to ensure that the costs are not already set off against taxable income.
All (direct or indirect) assignments of petroleum production licenses on the NCS are subject to the approval by the MPE under the Petroleum Act section 10-12 and of the MoF under the PTA section 10. In Regulations dated 1 July 2009 the MoF has decided that certain, typical, transactions for which the PTA section 10 applies shall be approved as such, on terms set out in the regulations, without any processing of applications, provided that the parties submit certain information to the MoF and the oil taxation authorities.
For transactions not covered by said Regulations, one would still have to apply for an approval from the MoF. The MoF may stipulate specific conditions, which also may deviate from the general tax legislation. The guiding principle for approval of transactions is that they should be revenue neutral to the State, i.e. that the total anticipated tax payments of the buyer and the seller before and after the transaction remain unchanged. Practice concerning such transactions has undergone considerable changes over the years, but will now follow the Regulations issued by the MoF on 1 July 2009.
According to said Regulations, the existing tax balances (depreciation and uplift) will (as the main rule) be transferred from the seller to the buyer with the assets. Thus, there will be no step up of the tax balances as a result of the transaction.
The following selected financial information has been extracted from the Group's audited financial statements as of and for the years ended 31 December 2016, 2015 and 2014 and the Group's unaudited interim financial statements for the three and nine months ended 30 September 2017 and 2016. The historical results of the Group are not necessarily indicative of its results for any future period. For a discussion of certain risks that could impact the business, operating results, financial condition, liquidity and prospects of the Group, see Section 1 "Risk Factors". The following summary of consolidated financial data should be read in conjunction with the other information contained in this Information Memorandum, including the Annual Financial Statements of the Group and the notes therein and the Interim Financial Statements, which have been incorporated in this Information Memorandum by reference; see Section 11 "Incorporation by Reference; Documents on Display".
The Company prepares its financial statements in accordance with the International Financial Reporting Standards (IFRS) adopted by EU and the Norwegian Accounting Act.
During the periods 2014 - 2016, some changes were made to the originally issued financial statements regarding presentation of certain comparative items in the income statement, statement of financial position and cash flow statement. In the tables below, the presentation principles from the originally issued financial statements have been applied.
The table below sets out a summary of the Group's income statement information for the three and nine months ended 30 September 2017 and 2016 and for the years ended 31 December 2016, 2015 and 2014.
| For the Three Months Ended 30 September |
For the Nine Months Ended 30 September |
For the Year Ended 31 December | |||||
|---|---|---|---|---|---|---|---|
| (USD 1000) | 2017 | 2016 | 2017 | 2016 | 2016 | 2015 | 2014 |
| Petroleum revenues | 600,808 | 247,213 | 1,838,450 | 719,254 | 1,260,803 | 1,158,683 | 411,996 |
| Other income | (4,620) | 779 | (1,511 ) | (10,748) | 103,326 | 63,119 | 52,235 |
| Total income | 596,188 | 247,993 | 1,836,939 | 708,506 | 1,364,129 | 1,221,802 | 464,230 |
| Exploration expenses Production costs |
63,887 134,411 |
30,843 32,188 |
169,521 376,303 |
103,172 105,678 |
147,453 226,818 |
76,404 141,000 |
164,336 66,754 |
| Depreciation | 175,334 | 114,649 | 543,532 | 349,231 | 509,027 | 480,959 | 160,254 |
| Impairments | 1,091 | 8,429 | 31,238 | 26,748 | 71,375 | 430,468 | 346,420 |
| Other operating expenses | 2,893 | 6,223 | 14,057 | 16,964 | 21,993 | 51,608 | 25,393 |
| Total operating expenses | 377,617 | 192,333 | 1,134,651 | 601,794 | 976,665 | 1,180,438 | 763,157 |
| Operating profit/loss | 218,571 | 55,660 | 702,288 | 106,712 | 387,464 | 41,364 | (298,927) |
| Interest income | 2,566 | 568 | 4,725 | 2,908 | 5,795 | 3,098 | 7,009 |
| Other financial income | 54,522 | 37,918 | 84,752 | 79,113 | 42,871 | 65,385 | 19,435 |
| Interest expenses | 27,129 | 20,107 | 88,397 | 61,933 | 82,161 | 82,174 | 83,845 |
| Other financial expenses | 39,427 | 23,487 | 140,654 | 46,527 | 63,515 | 140,679 | 19,296 |
| Net financial items | (9,469) | (5,107) | (139,574) | (26,439) | (97,011) | (154,971 ) | (76,697) |
| Profit/loss before taxes | 209,102 | 50,553 | 562,714 | 80,273 | 290,453 | (113,607) | (375,624) |
| Taxes (+)/tax income (-) | 97,065 | (12,880) | 321,963 | (21,101 ) | 255,482 | 199,045 | (96,485) |
| Net profit/loss | 112,037 | 63,433 | 240,751 | 101,974 | 34,971 | (312,652) | (279,139) |
| Weighted average no. of shares outstanding basic and diluted (shares 1 000) Basic and diluted |
337,137 | 202,619 | 337,737 | 202,619 | 236,583 | 202,619 | 165,811 |
| earnings/ (loss) per share | 0.33 | 0.31 | 0.71 | 0.50 | 0.15 | (1.54) | (1.68) |
|---|---|---|---|---|---|---|---|
| Statement of comprehensive income Profit/loss for the period |
112,037 | 63,433 | 240,751 | 101,974 | 34,971 | (312,652) | (279,139) |
| Items which may be reclassified over profit and loss (net of taxes) Currency translation |
|||||||
| adjustment Actuarial gain/loss pension |
(356) | (59) | (59) | - | (43,069) | ||
| plan | - | 17 | (897) | ||||
| Total comprehensive income in period |
112,037 | 63,433 | 240,395 | 101,914 | 34,911 | (312,636) | (323,105) |
The table below sets out a summary of the Group's financial position information as of 30 September 2017 and as of 31 December 2016, 2015 and 2014.
| As of | ||||||
|---|---|---|---|---|---|---|
| 30 September | As of 31 December | |||||
| (USD 1000) | 2017 | 2016 | 2015 | 2014 | ||
| ASSETS | ||||||
| Intangible assets | ||||||
| Goodwill | 1,817,486 | 1,846,971 | 767,571 | 1,186,704 | ||
| Capitalized exploration expenditures | 355,926 | 395,260 | 289,980 | 291,619 | ||
| Other intangible assets | 1,259,511 | 1,332,813 | 648,030 | 648,788 | ||
| Tangible fixed assets | ||||||
| Property, plant and equipment | 4,781,618 | 4,441,796 | 2,979,434 | 2,549,271 | ||
| Financial assets | ||||||
| Long-term receivables | 41,402 | 47,171 | 3,782 | 8,799 | ||
| Long-term derivatives | 23,238 | - | ||||
| Other non-current assets | 6,041 | 12,894 | 12,628 | 3,598 | ||
| Total non-current assets | 8,285,223 | 8,076,905 | 4,701,425 | 4,688,778 | ||
| Inventories Inventories |
73,762 | 69,434 | 31,533 | 25,008 | ||
| Receivables | ||||||
| Accounts receivable | 53,548 | 170,000 | 85,546 | 186,461 | ||
| Tax receivables | 145,245 | 400,638 | 126,391 | - | ||
| Other short-term receivables | 463,597 | 422,932 | 105,190 | 184,592 | ||
| Short-term derivatives | 14,106 | 45,217 | - | |||
| Other current financial assets | - | 2,907 | 3,289 | |||
| Cash and cash equivalents | ||||||
| Cash and cash equivalents | 80,764 | 115,286 | 90,599 | 296,244 | ||
| Total current assets | 831,022 | 1,178,290 | 487,384 | 695,594 | ||
| TOTAL ASSETS | 9,116,244 | 9,255,196 | 5,188,809 | 5,384,372 | ||
| EQUITY AND LIABILITIES | ||||||
| Equity | ||||||
| Share capital | 54,349 | 54,349 | 37,530 | 37,530 | ||
| Share premium | 3,150,567 | 3,150,567 | 1,029,617 | 1,029,617 |
| Other equity | (702,814) | (755,709) | (728,121 ) | (415,485) |
|---|---|---|---|---|
| Total equity | 2,502,102 | 2,449,207 | 339,026 | 651,662 |
| Non-current liabilities | ||||
| Pension obligations | - | 2,021 | ||
| Deferred taxes | 1,137,008 | 1,045,542 | 1,356,114 | 1,286,357 |
| Long-term provision' abandonment |
2,210,726 | 2,080,940 | 412,805 | 483,323 |
| Provisions for other liabilities | 89,209 | 218,562 | 1,638 | 12,044 |
| Long-term bonds | 625,726 | 510,337 | 503,440 | 253,141 |
| Long-term derivatives | 8,356 | 35,659 | 62,012 | 5,646 |
| Other interest-bearing debt |
1,396,158 | 2,030,209 | 2,118,935 | 2,037,299 |
| Current liabilities | ||||
| Trade creditors | 72,787 | 88,156 | 51,078 | 152,258 |
| Accrued public charges and indirect taxes | 15,280 | 39,048 | 9,060 | 6,758 |
| Tax payable | 265,080 | 92,661 | 189,098 | |
| Short-term derivatives |
2,128 | 5,049 | 13,506 | 25,224 |
| Short-term abandonment provision' | 152,668 | 75,981 | 10,520 | 5,728 |
| Other current liabilities | 639,016 | 583,844 | 310,675 | 273,813 |
| Total liabilities | 6,614,142 | 6,805,988 | 4,849,783 | 4,732,710 |
| TOTAL EQUITY AND LIABILITIES | 9,116,244 | 9,255,196 | 5,188,809 | 5,384,372 |
"Aker BP is currently in the process of updating certain accounting assumptions and estimates with regard to the year-end financial reporting. Among other things, the ongoing plugging and abandonment by the Maersk Invincible rig on the Valhall field, is considered when updating the decommissioning liability. Experience gained during those operations, indicate that the estimate is likely to decrease compared to the liability as of 30 September 2017.
The table below sets out a summary of the Group's changes in equity information for the nine months ended 30 September 2017 and for the years ended 31 December 2016, 2015 and 2014.
| Other eq uity | |||||||||
|---|---|---|---|---|---|---|---|---|---|
| Share Share capital premium |
Other comprehensive income | ||||||||
| (USD 1 000) | Other paid-in capital |
Actuarial gains/ (los ses) |
Foreign currency translation reserves |
Retained earnings |
Total other equity |
Total equity |
|||
| Equity as of 31.12.2013 | 27,656 | 564,736 | 573,083 | (223) | (48,334) | (592,818) | (68,292) | 524,100 | |
| Rights issue | 9,874 | 469,249 | (24,350) | (24,350) | 454,773 | ||||
| Transaction costs, rights issue Dividend distributed |
(4,368) | 261 | 261 | (4,107) | |||||
| Profitlloss for the period 01.01.2014 - 31.12.2014 Settlement of defined benefit |
(897) | (43,069) | (279,139) | (323,105) | (323,105) | ||||
| plan Equity as of 31.12.2014 |
37,530 | 1,029,617 | 573,083 | 1,016 (105) |
(115,491) | (1,016) (872,972) |
(415,485) | 651,662 | |
| Dividend distributed Profitlloss 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 Profitlloss for the period |
(62,500) | (62,500) | (62,500) | ||||||
| 01.01.2016 - 31.12.2016 Equity as of 31.12.2016 |
3,150,567 | 573,083 | (59) (115,550) |
34,971 (1,213,154) |
34,911 | 34,911 2,449,207 |
| 54,349 | (88) | (755,709) | ||||||
|---|---|---|---|---|---|---|---|---|
| Dividend distributed | (187,500) | (187,500) | (187,500) | |||||
| Profit/loss for the period - 30.09.2017 01.01.2017 |
(356) | 240,751 | 240,395 | 240,395 | ||||
| Equity as of 30.09.2017 | 54,349 | 3,150,567 | 573,083 | (88) | (115,907) | (1,159,903) | (702,814) | 2,502,102 |
The table below sets out a summary of the Group's cash flow information for the three and nine months ended 30 September 2017 and 2016 and for the years ended 31 December 2016, 2015 and 2014.
| For the Three Months | For the Nine Months | ||||||
|---|---|---|---|---|---|---|---|
| Ended 30 September | Ended 30 September | For the Year Ended 31 December | |||||
| (USD 1 000) | 2017 | 2016 | 2017 | 2016 | 2016 | 2015 | 2014 |
| CASH FLOW FROM OPERATING ACTIVITIES | |||||||
| Profit/ loss before taxes | 209,102 | 50,553 | 562,714 | 80,273 | 290,453 | (113,607) | (375,624) |
| Taxes paid during the period | (34,091) | (151 ) | (34,091) | (1,419) | (1,419) | (320,618) | (109,068) |
| Tax refund during the period | 263,791 | 83,666 | 263,791 | 83,666 | 212,944 | 87,662 | 190,532 |
| Depreciation | 175,334 | 114,649 | 543,532 | 349,231 | 509,027 | 480,959 | 160,254 |
| Net impairment losses | 1,091 | 8,429 | 31,238 | 26,748 | 71,375 | 430,468 | 346,420 |
| Accretion expenses | 32,757 | 6,816 | 97,212 | 18,691 | 47,977 | 26,351 | 12,410 |
| Interest expenses | 38,124 | 40,882 | 124,164 | 118,116 | 160,808 | 127,620 | 85,107 |
| Interest paid Gain/loss on license swaps without cash effect |
(27,454) | (32,405) | (114,224) | (109,319) | (161,634) | (124,276) | (83,910) (49,765) |
| Changes in derivatives | (37,628) | (32,126) | (67,568) | (33,140) | 10,408 | (793) | 10,616 |
| Amortized loan costs | 12,901 | 4,846 | 30,564 | 12,242 | 17,915 | 17,480 | 26,711 |
| Gain on change of pension scheme | (115,616) | ||||||
| Amortization of fair value of contracts | (825) | 7,330 | (2,878) | ||||
| Expensed capitalized dry wells | 20,534 | 9,313 | 56,155 | 43,702 | 51,669 | 11,682 | 99,061 |
| Changes in inventories, accounts payable | |||||||
| and receivables Changes in abandonment liabilities through |
19,591 | (31,465) | 56,090 | (92,088) | (317,488) | (13,060) | (530,150) |
| income statement Changes in other current balance sheet |
(1,131) | (1,569) | (1,952) | ||||
| items | 57,150 | 28,365 | 55,633 | 76,571 | 120,365 | 81,048 | 482,148 |
| NET CASH FLOW FROM OPERATING | |||||||
| ACTIVITIES | 730,376 | 251,372 | 1,612,541 | 573,275 | 895,652 | 686,467 | 262,791 |
| CASH FLOW FROM INVESTMENT ACTIVITIES Payment for removal and decommissioning of oil fields Disbursements on investments in fixed |
(26,673) | (2,473) | (54,640) | (5,493) | (12,237) | (12,508) | (14,087) |
| assets | (225,648) | (203,337) | (729,159) | (691,487) | (935,755) | (917,150) | (583,200) |
| Net of cash consideration paid for, and cash acquired from, BP Norge AS |
423,990 | 423,990 | 423,990 | ||||
| Acquisition of Marathon Oil AS (net of cash acquired) |
(1,513,591) | ||||||
| Acquisition of Premier Oil Norge AS (net of cash acquired) Disbursements on investments in capitalized |
(125,600) | ||||||
| exploration expenditures and other intangible assets |
(119,459) | ||||||
| Sale of tangible fixed assets and licences | (32,750) | (54,194) | (83,201) | (181,492) | (113,051) | (164,128) | |
| 8,862 | |||||||
| NET CASH FLOW FROM INVESTMENT ACTIVITIES |
(285,071) | 163,986 | (867,000) | (392,450) | (705,494) | (1,168,310) | (2,266,144) |
| CASH FLOW FROM FINANCING ACTIVITIES | |||||||
| Net proceeds from equity issuance | 474,755 | ||||||
| Repayment of short-term debt | (70,938) | (162,434) | |||||
| Repayment of long-term debt | (422,441 ) | (647,911) | (612,825) | (330,000) | (1,147,934) | ||
| Repayment of bond (DETNORD 1 ) | (87,536) | ||||||
| Repayment of bond (DETNOR03) Net proceeds from issuance of short-term |
(330,000) | (330,000) | |||||
| debt | 116,829 | ||||||
| Net proceeds from issuance of long-term | |||||||
| debt | 388,000 | 299,685 | 388,000 | 512,013 | 512,013 | 685,620 | 2,830,005 |
| Paid dividend NET CASH FLOW FROM FINANCING |
(62,500) | (187,500) | (62,500) | ||||
| ACTIVITIES | (426,941) | 299,685 | (777,411) | 512,013 | (163,312) | 284,683 | 2,023,684 |
| Net change in cash and cash equivalents | 18,365 | 715,043 | (31,870) | 692,838 | 26,846 | (197,160) | 20,331 |
| Cash and cash equivalents at start of period | 68,393 | 115,286 | 90,599 | 90,599 | 296,244 | 280,942 58 |
| 65,569 | |||||||
|---|---|---|---|---|---|---|---|
| Effect of exchange rate fluctuation on cash held |
(3,170) | 2,186 | (2,653) | 2,186 | (2,158) | (8,485) | (5,029) |
| CASH AND CASH EQUIVALENTS AT END OF PERIOD |
80,764 | 785,622 | 80,764 | 785,622 | 115,286 | 90,599 | 296,244 |
| SPECIFICATION OF CASH EQUIVALENTS AT END OF PERIOD |
|||||||
| Bank deposits and cash | 71,821 | 778,863 | 71,821 | 778,863 | 106,369 | 86,201 | 291,346 |
| Restricted bank deposits | 8,943 | 6,759 | 8,943 | 6,759 | 8,917 | 4,398 | 4,897 |
| CASH AND CASH EQUIVALENTS AT END OF PERIOD |
80,764 | 785,622 | 80,764 | 785,622 | 115,286 | 90,599 | 296,244 |
The table below sets out certain other unaudited non-IFRS key financial and operating information for the Company:
| Unit | As of or for the Nine Months Ended September 30, 2017 |
As of or for the Year Ended December 31, 2016 |
|
|---|---|---|---|
| EBITDA(1) | USDk | 1,277,058 | 967,866 |
| Earnings per share (EPS)12) | USD | 0.71 | 0.15 |
| Net interest-bearing debt'" | USDk | 1,941,121 | 2,425,260 |
| Equity ratio'" | 27.4 % | 26.5 % | |
| Debt-to-equity ratio'" | 2.6 | 2.8 | |
| Interest coverage ratto'" | 14.4 | 11.8 | |
| Production cost per barrel (7) | USD/boe | 10 | 8 |
| Depreciation per barrel'" | USD/boe | 14 | 18 |
(1) EBITDA is short for earnings before interest and other financial items, taxes, depreciation and amortization and impairments.
(2) Earnings per share (EPS) is net profit divided by number of shares outstanding.
EBITDA to interest expenses. (6)
Production cost per boe is production cost divided by number of barrels of oil equivalents produced in the corresponding period. (7)
Depreciation per boe is depreciation divided by number of barrels of oil equivalents produced in the corresponding period. (8)
The following tables set out unaudited pro forma financial information for the Group as of and for the year ended 31 December 2016 and is prepared under the assumption that the Transaction will close as described. For more details about the Transaction, please refer to Section 4.
The unaudited pro forma financial information has been prepared solely to show how the Transaction would have impacted on the consolidated income statement for the Group (including pro forma financial information for the acquisition of BP Norge as described in Section 9.3 below) for the twelve months ended 31 December 2016 had the Transaction occurred on 1 January 2016, and the consolidated statement of financial position as of 31 December 2016 had the Transaction occurred on 31 December 2016. The Transaction is expected to be completed by year end 2017, subject to approvals from the MPE and the MoF.
Although the unaudited pro forma financial information is based on estimates and assumptions based on current circumstances believed to be reasonable, actual results could have materially differed from those presented herein. There is a greater degree of uncertainty associated with pro forma figures than with actual reported financial information. The unaudited pro forma financial information has been prepared for illustrative purposes only and, because of its nature, the pro forma financial information addresses a hypothetical situation and, therefore, does not represent the company's actual financial position or results.
The unaudited pro forma financial information has been compiled to comply with the requirements as set forth in Section 3.5 of the Continuing Obligations by reference to Annex II of Commission Regulation (EC) no. 809/2004 implementing Directive 2003171 IEC of the European Parliament and of the Council of 4 November 2003 regarding information contained in prospectuses as well as the format, incorporation by reference and publication of such prospectuses and dissemination of advertisements, which pursuant to the Continuing Obligations apply correspondingly to information memorandums such as this Information Memorandum.
With respect to the unaudited pro forma financial information included in this Information Memorandum, KPMG AS has applied assurance procedures in accordance with ISAE 3420 Assurance Engagement to Report on Compilation of Pro Forma Financial Information Included in a Prospectus in order to express an opinion as to whether the unaudited pro forma financial information has been properly compiled on the basis stated, and that such basis is consistent with the accounting policies of the Company; see Appendix B (Independent Practitioner's Assurance Report on the Compilation of Pro-Forma Financial Information included in an Information Memorandum). There are no qualifications to this assurance report.
As of 30 September 2016, the Company completed the acquisition of BP Norge AS and issued an information memorandum including pro forma financial information to show how the BP acquisition would impacted the consolidated income statement for the Group for the twelve months ended 31 December 2015 had the transaction occurred on 1 January 2015, and the consolidated statement of financial position as of 31 December 2015 had the transaction occurred on 31 December 2015. As the BP acquisition was completed 30 September 2016, only three months of BP Norge activity was included in the Group Income Statement for 2016. Hence, the pro forma financial information below shall reflect both the BP acquisition and the Transaction. The pro forma financial information for the BP Norge acquisition and the pro forma financial information for the Transaction is included in 9.4.
The historical financial information for the Company used for compilation of the pro forma income Statement has been extracted from the Annual Financial Statements for the Company as of and for the year ended 31 December 2016. These documents are incorporated by reference to this Information Memorandum; See Section 11 "Incorporation by Reference; Documents on Display".
The financial information of BP Norge AS has been extracted from the Annual Financial Statements for BP Norge as of and for the year ended 31 December 2016 prepared in accordance with Norwegian generally accepted accounting principles ("NGAAP") and in compliance with the 1998 Accounting Act. The Financial Statements for BP Norge are set out in Appendix B.
The financial information of Hess Norge has been extracted from the Annual Financial Statements for Hess Norge as of and for the year ended 31 December 2016 prepared in accordance with Norwegian generally accepted accounting principles ("NGAAP") and in compliance with the 1998 Accounting Act. The Financial Statements for Hess Norge are set out in Appendix C.
Certain reclassifications have been done to conform Hess Norge's 2016 financial statement presentation to that of the Company. The tables below show the Hess Norge 2016 financial statement presented in NOK, the recalculation to USD and the adjustments made to comply with the form of the financial statement presented by the Company. The currency rate for conversion to USD is the average 2016 rate (8.3987) for the income statement and the year end 2016 rate (8.6520) for the statement of financial position.
| Year ended 31 December 2016 | NOK (1000) | USD (1 000) | Adjusted presentation* USD (1 000) |
|---|---|---|---|
| Petroleum revenues | 424,484 | ||
| Crude oil sales | 3,124,852 | 372,064 | |
| Gas sales | 374,906 | 44,639 | |
| Natural gas liquid sales | 65,359 | 7,782 | |
| 60 |
| Other income | (136) | (16) | (16) |
|---|---|---|---|
| Total income | 3,564,981 | 424,468 | 424,468 |
| Production costs | 1,965,822 | 234,063 | 248,541 |
| Salaries and benefits | 121,595 | 14,478 | - |
| Depreciation | 2,752,808 | 327,766 | 327,766 |
| Impairments | - | - | |
| Other operating expenses | 172,431 | 20,531 | 20,531 |
| Total operating expenses | 5,012,656 | 596,838 | 596,838 |
| Operating profitlloss | (1,447,675) | (172,370) | (172,370) |
| Interest income | 1,936 | 231 | 231 |
| Other financial income | 24,991 | 2,976 | 2,976 |
| Interest expenses | (1,458,150) | (173,616) | (115,322) |
| Other financial expenses | (88) | (10) | (58,305) |
| Net financial items | (1,431,311 ) | (170,420) | (170,420) |
| Profitlloss before taxes | (2,878,986) | (342,790) | (342,790) |
| Taxes (+)/tax income (-) | (1,588,549) | (189,142) | (189,142) |
| Net profit/loss | (1,290,437) | (153,648) | (153,648) |
* Payroll expenses have been reclassified to production cost, and accretion expenses have been reclassified from interest expenses to other financial expenses based on information from Hess Norge.
Statement of financial position:
| Adjusted presentation* |
|||
|---|---|---|---|
| Year ended 31 December 2016 | NOK (1000) | USD (1000) | USD (1000) |
| ASSETS | |||
| Tangible fixed assets | |||
| Production facilities in operation | 33,626,392 | 3,900,974 | 3,901,005 |
| Office equipment and art | 270 | 31 | - |
| Financial assets | |||
| Long-term receivables | 68,534 | 7,951 | 7,951 |
| Total non-current assets | 33,695,196 | 3,908,955 | 3,908,955 |
| Inventories | |||
| Inventories | 120,683 | 14,000 | 14,000 |
| Receivables | |||
| Underlift | 72,634 | 8,426 | |
| Accounts receivable | 626,702 | 72,703 | 72,703 |
| Other short-term receivables | 273,224 | 31,697 | 40,123 |
| Cash and cash equivalents | |||
| Cash and cash equivalents | 485,522 | 56,325 | 56,325 |
| Total current assets | 1,578,765 | 183,151 | 183,151 |
| TOTAL ASSETS | 35,273,961 | 4,092,107 | 4,092,107 |
| EQUITY AND LIABILITIES | |||
| Equity | |||
| Share capital | 2,400 | 278 | 278 |
61
| Share premium | 2,212,279 | 256,645 | 256,645 |
|---|---|---|---|
| Total equity | 2,214,679 | 256,923 | 256,923 |
| Non-current liabilities | |||
| Pension obligations | 6,267 | 727 | |
| Deferred taxes | 1,041,822 | 120,861 | 120,861 |
| Long-term abandonment provision | 8,630,750 | 1,001,247 | 1,001,247 |
| Provisions for other liabilities | 727 | ||
| Intercompany debt | 22,757,980 | 2,640,137 | 2,640,137 |
| Current liabilities | |||
| Trade creditors | 294,633 | 34,180 | 34,180 |
| Accrued public charges and indirect taxes | 2,799 | 325 | 325 |
| Short-term debt to group companies | 325,030 | 37,706 | 37,706 |
| Total liabilities | 33,059,281 | 3,835,183 | 3,835,183 |
| TOTAL EQUITY AND LIABILITIES | 35,273,961 | 4,092,107 | 4,092,107 |
* Underlift has been reclassified to other short-term receivables based on information from Hess Norge
| BP Norge notes to IFRS |
Hess Norge Notes to IFRS |
Pro Forma for BP Acquisition |
|||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| Income statement 2016 | Aker BP | BP Norge | IFRS | Pro forma | and Pro | Pro forma for | and Pro | ||||
| (USD 1 000) | (IFRS) | (NGAAP)(3) | adjustments | adjustments | Forma adjustments |
BP Acquisition | Hess Norge (NGAAP)(2) |
IFRS adjustments |
Pro forma adjustments |
Forma adjustments |
and Hess Acquisition |
| Operating revenues and expenses | |||||||||||
| Petroleum revenues | 1,129,939 | 619,199 | 18,189 | 1 | 1,767,327 | 424,484 | (7,251) | 1 | 2,184,561 | ||
| Other operating revenues | (12,242) | 945,584 | 43,732 | (866,217) | 2 | 110,857 | (16) | 110,841 | |||
| Total operating revenues | 1,117,697 | 1,564,783 | 61,921 | (866,217) | 1,878,185 | 424,468 | (7,251) | 2,295,402 | |||
| Exploration expenses | 138,878 | 3,100 | 141,978 | 141,978 | |||||||
| Production costs | 166,219 | 357,825 | 4,462 | 1,2,4 | 528,505 | 248,540 | (7,276) | 1,2 | 769,769 | ||
| Depreciation and amortization | 495,876 | 284,042 | (78,698) | (116,706) | 3,4 | 584,514 | 327,766 | (63,839) | (204,247) | 3,4 | 644,194 |
| Impairments | 71,375 | 71,375 | 71,375 | ||||||||
| Provision for decommissioning | 539,542 | (539,542) | 4 | ||||||||
| Other operating expenses | 24,549 | 10,476 | 35,025 | 20,531 | 226 | 6 | 55,782 | ||||
| Total operating expenses | 896,897 | 1,194,984 | (613,779) | (116,706) | 1,361,398 | 596,837 | (71,115) | (204,021 ) | 1,683,098 | ||
| Operating profit (loss) | 220,800 | 369,799 | 675,700 | (749,511) | 516,787 | (172,369) | 63,864 | 204,021 | 612,304 | ||
| Interest income | 5,516 | 8,297 | 13,813 | 231 | 14,044 | ||||||
| Other financial income | 64,068 | 64,068 | 2,976 | 67,043 | |||||||
| Interest expenses | 89,438 | 25,747 | (24,272) | 5 | 90,913 | 115,322 | (70,307) | 7 | 135,928 | ||
| Other financial expenses | 81,101 | 13,109 | 39,973 | 39,088 | 4 | 173,271 | 58,305 | 5,386 | 4 | 236,962 | |
| Net financial items | (100,955) | (30,559) | (39,973) | (14,816) | (186,303) | (170,421) | - | 64,920 | (291,803) | ||
| Profit I (loss) before taxes | 119,844 | 339,239 | 635,727 | (764,327) | 330,484 | (342,789) | 63,864 | 268,942 | 320,501 | ||
| Taxes (+)/tax income (-) | 84,874 | (372,688) | 476,977 | 66,610 | 6 | 255,772 | (189,142) | 31,626 | 172,689 | 8 | 270,944 |
| Net income | 34,971 | 711,928 | 158,750 | (830,937) | 74,712 | (153,647) | 32,239 | 96,253 | 49,556 |
| 31.12.2016 | Aker BP | Hess Norge | IFRS | Pro Forma | Notes to IFRS and Pro Forma adjustment |
Pro Forma as of 31 December |
|---|---|---|---|---|---|---|
| (USD 1 000) | (IFRS) | (NGAAP)(3) | adjustments | adj ustments | s | 2016 |
| ASSETS | ||||||
| Intangible assets | ||||||
| Goodwill | 1,846,971 | 178,818 | 5 | 2,025,789 | ||
| Capitalized exploration expenditures | 395,260 | 5 | 395,260 | |||
| Other intangible assets | 1,332,813 | 484,176 | 5 | 1,816,989 | ||
| Deferred tax assets | 1,860,571 | 5,8 | 1,860,571 | |||
| Tangible fixed assets | ||||||
| Property, plant and equipment | 4,441,796 | 3,901,005 | (3,008,416) | 4,5 | 5,334,385 | |
| Financial assets | ||||||
| Long-term receivables | 47,171 | 7,951 | 55,122 | |||
| Other non-current assets | 12,894 | 12,894 | ||||
| Total non-current assets | 8,076,905 | 3,908,955 | (484,850) | 11,501,010 | ||
| Inventories | ||||||
| Inventories | 69,434 | 14,000 | 83,434 | |||
| Receivables | ||||||
| Accounts receivable | 170,000 | 72,703 | 242,703 | |||
| Other short-term receivables | 422,932 | 40,123 | 463,055 | |||
| Tax receivables | 400,638 | 400,638 | ||||
| Cash and cash equivalents | ||||||
| Cash and cash equivalents | 115,286 | 56,325 | 171,611 | |||
| Total current assets | 1,178,290 | 183,151 | - | - | 1,361,440 | |
| TOTAL ASSETS | 9,255,195 | 4,092,107 | - | (484,850) | 12,862,452 | |
| EQUITY AND LIABILITIES | ||||||
| Equity | ||||||
| Share capital | 54,349 | 278 | 2,386 | 5 | 57,013 | |
| Share premium | 3,150,567 | 256,645 | (11,150) | 250,614 | 5,6 | 3,646,675 |
| Other equity | (755,709) | (226) | 5,6 | (755,935) | ||
| Total equity | 2,449,207 | 256,923 | (11,150) | 252,773 | 2,947,753 |
Non-current liabilities
| TOTAL EQUITY AND LIABILITIES | 9,255,195 | 4,092,107 | (484,850) | 12,862,452 | ||
|---|---|---|---|---|---|---|
| Total liabilities | 6,805,988 | 3,835,183 | 11,150 | (737,623) | 9,914,698 | |
| Other current liabilities | 583,844 | 39,569 | 5,6 | 623,413 | ||
| Short-term abandonment provision | 75,981 | 75,981 | ||||
| Short-term debt to group companies | 37,706 | (37,706) | ||||
| Short-term derivatives | 5,049 | 5,049 | ||||
| Tax payable | 92,661 | 92,661 | ||||
| Accrued public charges and indirect taxes |
39,048 | 325 | 39,373 | |||
| Trade creditors | 88,156 | 34,180 | 122,336 | |||
| Current liabilities | ||||||
| Other interest-bearing debt |
2,030,209 | 1,624,066 | 5,7 | 3,654,275 | ||
| Intercompany debt | 2,640,137 | (2,640,137) | ||||
| Long-term derivatives | 35,659 | 35,659 | ||||
| Long-term bonds | 510,337 | 510,337 | ||||
| Provisions for other liabilities | 218,562 | 727 | 97 | 131,169 | 2, 5 | 350,556 |
| Long-term abandonment provision | 2,080,940 | 1,001,247 | 277,738 | 3,4,5 | 3,359,925 | |
| Deferred taxes | 1,045,542 | 120,861 | 11,053 | (132,323) | 5,8 | 1,045,133 |
(3) Statement of financial position information for Hess Norge as for the year ended December 31, 2016 was converted from NOK to U.S. dollars using the period end exchange rate of USD1.00 to NOK8.6200, as published by the Central Bank of Norway. In addition, certain reclassifications have been made within tangible fixed assets, receivables and non-current liabilities by the Company to make the Hess Norge statement of financial position comparable to that of Aker BP.
The first column to the left in the income statement above shows amount derived from the audited 2016 separate financial statement (parent company) of Aker BP. As described in note 3 in Aker BP's 2016 financial statements, the business assets and liabilities of BP Norge were transferred to Aker BP on December 1, 2016 and the last month of the activity previously held in BP Norge is included in the audited separate financial statements of Aker BP. The next column reflects information derived the 2016 income statement of BP Norge, which is presented in NOK in the audited 2016 financial statements. The financial information of BP Norge has been converted from NOK to USD applying the average USD/NOK rate for the first eleven months of 2016 of USD1.00 to NOK8.3839, as published by the Central Bank of Norway, corresponding to the period during which BP Norge conducted business operations in 2016. In addition, certain reclassification adjustments have been made to make the BP Norge income statement comparable to that of Aker BP.
BP Norge has historically presented its financial information in accordance with NGAAP. In connection with the compilation of the unaudited pro forma financial information, unaudited differences between IFRS and NGAAP were identified and the resulting adjustments are presented in column three in the table above. The fourth column shows the pro forma adjustments as described above and, when applicable, these adjustments are disclosed separately in each note below. The next column includes references to the notes below and the total pro forma financial information is presented in the column to the far right.
All amounts are expressed in thousands of USD unless otherwise specified.
Aker BP recognizes revenues from petroleum products based on its ideal share of production during the period, regardless of actual sales (entitlement method). BP Norge has recognized revenues when title passes to the customer at the point of delivery based on the contractual terms of the sales agreements (sales method). The sales method recognizes a cost or reduction in cost for the cost-value of the difference between actual sales and produced volumes.
Hence, BP Norge revenues have been adjusted to reflect the ideal share of production instead of the actual sales. The costs related to the adjusted revenues were also adjusted. The income statement is adjusted as follows:
December 31, 2016 Income statement(l) (in millions of USD) Increased revenue USD18.2 Increased production cost USD6.2 Net impact before tax USD12.0
Year ended
(l)The adjustments will have continuing impact.
Other income is adjusted to reflect the IFRS gain on the pension scheme settlement. Calculation of the defined benefit obligation under NRS 6 ("NRS 6") and lAS 19 ("lAS 19") is based on different actuarial assumptions, which results in a higher IFRS liability and thus a higher net gain on the settlement. The gain arose as the defined benefit scheme in BP Norge was replaced by a defined contribution scheme during the fourth quarter of 2016.
In addition BP Norge has applied a NGAAP specific rule (NRS 6), allowing that accumulated losses of the benefit obligation are amortized over the remaining service period of active plan participants. This method is not in accordance with lAS 19, where any actuarial gains and losses need to be recognized immediately in other comprehensive income.
The different actuarial assumption amounts to an increase in other income of USD43,732. The reversal of amortization of actuarial gains/losses amounts to USD2,091 reduction in production costs. These adjustments will not have a continuing impact.
The activity of BP Norge was transferred to Aker BP on December 1, 2016 resulting in a net gain of USD866,217. The gain was calculated based on the difference between the consideration paid by Aker BP ASA and the net book values of the transferred assets in BP Norge. As this was a transaction between BP Norge and Aker BP, the gain has been removed as a pro forma adjustment. This adjustment will not have a continuing impact.
Both the Company and BP Norge apply the unit of production method ("UOP") as the depreciation method for oil and gas fields. However, the Company's UOP is based on proved and probable reserves while BP Norge applies only proved reserves in its calculation of depreciation. Hence, Aker BP applies a wider reserve definition as basis for the depreciation of oil and gas fields, which means that the depreciation from BP Norge is expected to decrease.
| Year ended December 31, 2016 |
|
|---|---|
| Income statement | (in millions of USD) |
| Decreased depreciation based on 2P reserves | USD(102.3) |
| Depreciation of ARO asset (see note on decommissioning below) | USD23.6 |
| Net impact before tax | USD(78.7) |
(b) Pro forma adjustment
When the BP Norge assets are recognized in the Aker BP statement of financial position the values are based on the Purchase price allocation ("PPA"). These values are allocated based on the estimated assets net present value after tax. The values are lower than the historical book value in BP Norge. In the pro forma financial statements the total depreciation should equal the calculated UOP depreciation, and the pro forma adjustment reflects this adjustment.
The BP Norge depreciation is therefore adjusted as follows:
| Year ended December 31,2016 |
|
|---|---|
| Income statement | (in millions of USD) |
| Depreciation field excess values | USD(116.7) |
All the adjustments will have a continuing impact.
In accordance with IFRS the Company recognizes asset retirement obligations ("ARD"), based on the net present value of future related decommissioning and removal costs. A corresponding asset is capitalized as a tangible fixed asset and depreciated using the unit of production method. Changes in the time value (net present value) of the ARD are recognized as financial expenses in the income statement and increases ARD liability in the statement of financial position. Changes in the best estimate for expenses related to decommissioning and removal are recognized in the statement of financial position. The discount rate used in the calculation of the fair value of the decommissioning and removal obligation is the risk-free rate with the addition of a credit risk element.
BP Norge has accrued the estimated costs of decommissioning and removal of producing facilities using the UOP method based on proved reserves. To align BP Norge costs to IFRS, the ARD including the related depreciation and accretion has been estimated, which results in the following adjustments:
| Year ended December 31,2016 |
|
|---|---|
| Income statement | (in millions of USD) |
| Adjustment provision for decommissioning cost | USD(539.5) |
| Depreciation of ARD asset | USD23.6 |
| Accretion | USD40.0 |
The initial amount presented as provision for decommissioning in the NGAAP income statement of BP Norge for the year ended December 31, 2016 was USD539.5 million. Of this, a total of USD539.2 million is adjusted as an IFRS adjustment. The remaining USD369 was reclassified to production costs. This is related to changes in removal estimates for Gassled assets, as well as removal obligations for fields previously sold by BP Norge. As shipper of gas through the Gassled infrastructure, BP Norge has a contractual obligation to cover a proportionate share of the removal of the Gassled facilities. Since BP Norge is not a Gassled owner, no corresponding removal asset is recognized and the cost will be charged directly to the income statement based on shipped gas for the year.
In the PPA, the Company has applied a different estimate for decommissioning cost than BP Norge. This results in an increased provision with a corresponding asset. The asset, along with the excess value for producing licenses, is depreciated using the UOP method based on proved and probable reserves. The calculated impact on depreciation and accretion in the income statement is as follows:
Year ended December 31, 2016
| Income statement | (in millions of USD) |
|---|---|
| Depreciation of negative excess value | USD(116.l) |
| Accretion expense | USD39.1 |
| Discount rate applied for accretion | 5.89% |
The fair value of the fixed assets (post tax) identified in the PPA is less than the fixed assets value in BP Norge (pretax). Hence, the adjustment above decreases the depreciation originally charged to the BP Norge financial statements.
All the adjustments will have continuing impact.
The intercompany loan in BP Norge was settled as part of the transaction, and is adjusted as if the loan had been non-existent as of January 1, 2016. The related interest expense for 2016 of USD24,272 has been adjusted accordingly. This adjustment will have continuing impact.
As allowed under NGMP, the tax impact of future uplift is recognized as a deferred tax asset in BP Norge's financial statements. Such recognition is not allowed under lAS 12 and is adjusted as an IFRS difference in the pro forma income statements, amounting to USD18.9 million. This adjustment will have continuing impact. Each NGMP and pro forma adjustment is charged with the applicable tax rate. For 2016, the statutory tax rate was 25% and the special petroleum tax rate was 53%.
The sixth column to the left in the unaudited pro forma condensed consolidated income statement, above, shows the pro forma income statement of Aker BP reflecting the impact of the BP Acquisition. The seventh column reflects the 2016 income statement of Hess Norge, which is presented in NOK in the audited 2016 financial statements. The financial information of Hess Norge has been converted from NOK to USD applying the average USD/NOK rate for the year ended December 31, 2016 of USD1.00 to NOK8.3987, as published by the Central Bank of Norway. In addition, certain reclassification adjustments have been made within operating expense classifications to make the Hess Norge income statement comparable to that of Aker BP.
Hess Norge has historically presented its financial information in accordance with NGMP. In connection with the compilation of the unaudited pro forma financial information, unaudited differences between IFRS and NGMP were identified and the resulting adjustments are presented in the eighth column in the unaudited pro forma consent consolidated income statement, above. The ninth column shows the pro forma adjustments as described above and, when applicable, these adjustments are disclosed separately in each note below. The tenth column includes references to the notes below and the total pro forma financial information reflecting the BP Acquisition and the Transaction is presented in the column to the far right.
All amounts are expressed in thousands of USD unless otherwise specified.
Aker BP recognizes revenues from petroleum products based on its ideal share of production during the period, regardless of actual sales (entitlement method). Hess Norge has recognized revenues when title passes to the customer at the point of delivery based on the contractual terms of the sales agreements (sales method). The sales method recognizes a cost or reduction in cost for the cost-value of the difference between actual sales and produced volumes.
Hence, Hess Norge revenues have been adjusted to reflect the ideal share of production instead of the actual sales. The costs related to the adjusted revenues were also adjusted. The income statement is adjusted as follows:
| Year ended December 31,2016 |
|
|---|---|
| Income statement(1) | (in millions of USD) |
| Decreased revenue. | USD1.3 |
| Decreased production cost | USD1.3 |
| Net impact before tax | USDO.O |
(liThe adjustments will have continuing impact.
(a) IFRS adjustment
Hess Norge has applied a NGAAP specific rule (NRS 6), allowing that accumulated losses of the benefit obligation are amortized over the remaining service period of active plan participants. This method is not in accordance with lAS 19, where any actuarial gains and losses need to be recognized immediately in other comprehensive income.
The GAAP difference described above give rice to an increase of USD91 in increased pension liability. The reversal of amortization of actuarial gains/losses amounts to USD25 reduction in production costs. These adjustments will not have a continuing impact.
(a) IFRS adjustment
Both the Company and Hess Norge apply the unit of production method ("UOP") as the depreciation method for oil and gas fields. However, the Company's UOP is based on proved and probable reserves while Hess Norge applies only proved reserves in its calculation of depreciation. Hence, Aker BP applies a wider reserve definition as basis for the depreciation of oil and gas fields, which means that the depreciation from Hess Norge would have decreased by USD63,839 if Hess Norge had included proved and probable reserves as the basis for depreciation.
(b) Pro forma adjustment
When the Hess Norge assets are recognized in the Aker BP statement of financial position the values are based on the Purchase price allocation ("PPA"). These values are allocated based on the estimated assets net present value after tax. The values are lower than the historical book value in Hess Norge. In the pro forma financial statements the total depreciation should equal the calculated UOP depreciation, and the pro forma adjustment reflects this adjustment.
The Hess Norge depreciation is therefore adjusted as follows:
31,2016
(in millions of USD)
Depreciation field excess values . USD(204.2)
All the adjustments will have a continuing impact.
(a) Pro forma adjustment
In the PPA, the Company has applied a different estimate for decommissioning cost than Hess Norge. This results in an increased provision with a corresponding asset. The asset, along with the excess value for producing licenses, is depreciated using the UOP method based on proved and probable reserves. The calculated impact on depreciation and accretion in the income statement is as follows:
| Year ended December 31, 2016 |
|
|---|---|
| Income statement | (in millions of US D) |
| Depreciation of negative excess value | USD(204.2) |
| Accretion expense | USD5.4 |
The value of the fixed assets (post tax) identified in the PPA is less than the fixed assets value in BP Norge (pretax). Hence, the adjustment above decreases the depreciation originally charged to the BP Norge financial statements.
All the adjustments will have continuing impact.
(a) Pro forma adjustments
The Company has for the purpose of the pro forma financial information provisionally performed an allocation of the cost of the business combinations to the assets acquired and liabilities and contingent liabilities assumed in accordance with IFRS 3. This allocation has formed the basis for the amortisation and depreciation charges in the unaudited Pro Forma condensed consolidated Income Statements and the presentation in the unaudited Pro Forma condensed consolidated Statement of Financial Position.
The cash consideration, including interim settlement as defined by the agreement, is for the purpose of the preliminary PPA estimated to USD2,124 million, of which USD500 million is funded by equity increase. Net book value in Hess Norge AS as of 31 December 2016, after the IFRS adjustments is USD246 million, resulting in an excess of the fair value over the net book value of USD1 ,878 million.
The Company has provisionally determined that the excess value based on the purchase price compared to book values as of 31 December 2016 primarily relates to licenses related to producing properties, deferred taxes and goodwill. As there exists no pre-tax market for oil and gas assets in Norway, cf. the PTA section 10, no tax amortisation benefit is calculated. The final allocation may significantly differ from this allocation and this could materially have affected the depreciation and amortisation of excess values in the unaudited pro forma condensed consolidated income statement and the presentation in the unaudited pro forma condensed consolidated statement of financial position. The main uncertainties relate to fair value of the licenses and the value of decommissioning liabilities.
The historical depreciation in Hess Norge AS has been based on proved reserves, and for pro forma purposes the opening book values have not been adjusted to reflect depreciation based on proved and probable reserves. Going forward, the excess value will be depreciated in accordance with UOP based on proved and probable reserves in line with the reserve base applied for the Company's other oil and gas assets.
Goodwill will not be depreciated, but will be subject to yearly impairment test in accordance with lAS 36. No impairment is recognised in the unaudited pro forma condensed consolidated financial information.
| Provisional allocation of excess value: | (USD million) |
|---|---|
| Value of licenses, including decommissioning assets | (2,524) |
| Increased decommissioning liability | (278) |
| Negative contract value | (131 ) |
| Intercompany loan to be repaid | 2,640 |
| Deferred tax asset (78% rate) | 1,992 |
| Goodwill | 179 |
| Total excess value | 1,878 |
The fair values of these assets and liabilities have been determined on a preliminary basis and is subject to change pending additional information that may become available prior to or upon completion of the transaction. The split between the various assets may subsequently change after the completion of the purchase price allocation. If more of the cost of the business combination should be allocated to producing properties the pro forma income statements would have shown higher amortisation expenses.
As a consequence of the Transaction, all previous intercompany balances with the Hess group is expected to be settled. Intercompany debt has thus been reclassified to external debt.
All these adjustments will have continuing impact.
(a) Pro forma adjustments
The external transaction costs to be expensed and unrelated to equity increase are estimated to USD226,000. These are not tax deductible and are expensed in the unaudited pro forma condensed consolidated Income Statements and included in the unaudited pro forma condensed consolidated statement of financial position as a reduction in other equity and a corresponding increase in other current liabilities. This pro forma adjustment will not have continuing impact.
The external cost related to capital increase is estimated to USD1,118,000 (net of 25% tax) and is recorded against other paid in capital in the Pro Forma Statements of Position. This pro forma adjustment will not have continuing impact.
The intercompany loan in Hess Norge was settled as part of the transaction, and is adjusted as if the loan had been non-existent as of January 1, 2016. The related interest expense for 2016 of USD115,322 has been adjusted accordingly. This has been offset by the assumed interest expense from the USD1.5 billion loan that will be established upon completion, amounting to USD45,015. Hence the net impact on interest expense is a decrease of USD70,307. This adjustment will have continuing impact.
As allowed under NGAAP, the tax impact of future uplift is recognized as a deferred tax asset in Hess Norge's financial statements. Such recognition is not allowed under lAS 12 and is adjusted as an IFRS difference in the pro forma income statements, amounting to USD18.1 million. The corresponding adjustment in the statement of financial position is USD11.1 million. This adjustment will have continuing impact.
Each NGAAP and pro forma adjustment is charged with the applicable tax rate. For 2016, the statutory tax rate was 25% and the special petroleum tax rate was 53%. The corresponding rates for 2017 are 24% and 54%.
The following selected financial information has been extracted from the audited consolidated financial statements for Hess Norge as of and for the years ended 31 December 2016, 2015 and 2014. The historical results of Hess Norge are not necessarily indicative of its results for any future period. For a discussion of certain risks that could impact the business, operating results, financial condition, liquidity and prospects of Hess Norge, see Section 1 "Risk Factors".
The annual accounts of Hess Norge AS have been prepared in accordance with Norwegian law, regulations for preparing annual accounts, and generally accepted accounting principles in Norway.
The table below sets out a summary of information extracted from the audited income statement of Hess Norge for the years ended 31 December 2016, 2015 and 2014.
| For the Years Ended 31 December | |||
|---|---|---|---|
| (NOK 1000) | 2016 | 2015 | 2014 |
| Crude oil sales | 3,124,852 | 4,103,948 | 5,744,804 |
| Gas sales | 374,906 | 697,394 | 688,863 |
| Natural gas liquid sales | 65,359 | 99,627 | 151,913 |
| Other income | (136) | 26,000 | 142 |
| Total operating income | 3,564,981 | 4,926,969 | 6,585,722 |
| Production and transportation costs | 1,965,822 | 2,106,767 | 2,236,542 |
| Exploration costs | (1,217) | 105 | |
| Salaries and benefits | 121,595 | 147,413 | 122,040 |
| Ordinary depreciation and impairment | 2,752,808 | 6,108,500 | 2,825,422 |
| Other operating costs | 172,431 | 197,629 | 115,512 |
| Total operating costs and expenses | 5,012,656 | 8,559,093 | 5,299,620 |
| Income from operations | (1,447,675) | (3,632,124) | 1,286,101 |
| Interest income | 1,936 | 6,122 | 1,272 |
| Interest expense | (1,458,150) | (1,525,600) | (1,488,445) |
| Foreign exchange gain/ (loss) | 24,991 | 82,290 | 107,808 |
| Other finance expenses | (88) | (132) | (119) |
| Net financial income/ (expenses) | (1,431,312) | (1,437,320) | (1,379,484) |
| Income before taxes | (2,878,986) | (5,069,444) | (93,383) |
| Taxes | (1,588,549) | (3,175,449) | 462,332 |
| Net income | (1,290,437) | (1,893,994) | (555,715) |
The table below sets out a summary of information extracted from the audited balance sheet of Hess Norge as of 31 December 2016, 2015 and 2014.
| As of 31 December | ||||
|---|---|---|---|---|
| (NOK 1000) | 2016 | 2015 | 2014 | |
| Non-current assets | ||||
| Production facilities in operation | 33,626,392 | 37,264,129 | 42,328,421 | |
| Office equipment and art | 270 | 41 | 181 | |
| Long-term receivables | 68,534 | 100,928 | 68,617 | |
| Total non-current assets | 33,695,196 | 37,365,098 | 42,397,219 | |
| Current assets | ||||
| Spare parts | 120,683 | 324,863 | 381,865 | |
| Underlift | 72,634 | 135,264 | 117,108 | |
| Accounts receivable | 626,702 | 279,388 | 358,186 | |
| Intercompany receivables | - | 1,065 | 1,065 | |
| Prepaid expenses and other receivables | 273,224 | 360,687 | 345,415 | |
| Cash and deposits | 485,522 | 195,087 | 44,457 | |
| Total current assets | 1,578,765 | 1,296,355 | 1,248,095 | |
| Total assets | 35,273,961 | 38,661,452 | 43,645,314 | |
| Shareholder's equity | ||||
| Capital stock | 2,400 | 2,300 | 2,100 | |
| Share premium | 2,212,279 | 2,125,145 | 903,900 | |
| Other equity | 137,966 | 2,031,960 | ||
| Total shareholder's equity | 2,214,679 | 2,265,411 | 2,937,960 | |
| Long-term liabilities | ||||
| Deferred income taxes | 1,041,822 | 2,630,270 | 5,775,298 | |
| Pension liability | 6,267 | 1,899 | 974 | |
| Dismantlement provision | 8,630,750 | 10,199,973 | 10,522,587 | |
| Intercompany debt | 22,757,980 | 22,757,980 | 23,406,673 | |
| Total long-term liabilities | 32,436,820 | 35,590,122 | 39,705,532 | |
| Current liabilities | ||||
| Accounts payable and accrued liabilities | 294,633 | 493,112 | 661,740 | |
| Bank overdraft | 93,817 | 300,590 | ||
| Intercompany liabilities | 325,030 | 213,880 | 35,668 | |
| Overlift | 1,732 | |||
| Public duties payable | 2,799 | 3,379 | 3,824 | |
| Total current liabilities | 622,462 | 805,920 | 1,001,822 | |
| Total equity and liabilities | 35,273,961 | 38,661,452 | 43,645,314 |
The table below sets out a summary of information extracted from the audited cash flow state,ments of Hess Norge for the years ended 31 December 2016, 2015 and 2014.
| For the Years Ended 31 December | ||||
|---|---|---|---|---|
| (NOK 100O) | 2016 | 2015 | 2014 | |
| Cash flow from operating activities | ||||
| Income before taxes | (2,878,986) | (5,069,444) | (93,383) | |
| Taxes received/ (paid) | 30,422 | (10,475) | ||
| Depreciation, depletion and amortization | 2,752,808 | 3,856,967 | 2,825,422 | |
| Impairment | 2,251,533 | |||
| Accretion on dismantlement less payments | (576,218) | (931,807) | (608,455) | |
| Net change in long term receivables | 32,394 | (32,311 ) | 31 | |
| Net change in long term accruals | 4,368 | 925 | (859) | |
| Net change in accounts receivable | (347,314) | 78,798 | 160,537 | |
| Net change in accounts payable | (198,480) | (168,628) | 19,462 | |
| Net change in other current accounts and other changes | 464,176 | 203,071 | 586,433 | |
| Net cash flow from operating activities | (747,251) | 219,527 | 2,878,712 | |
| Cash flow from investing activities | ||||
| Purchase of tangible fixed assets | (108,270) | (434,876) | (1,979,181) | |
| Net cash flow from investing activities | (108,270) | (434,876) | (1,979,181) | |
| Cash flow from financing activities | ||||
| Proceeds from new intercompany debt | - | (648,693) | 1,257 | |
| Net change in overdraft | (93,817) | (206,773) | (863,758) | |
| Proceeds from issuance of equity | 1,239,773 | 1,221,445 | ||
| Net cash flow from financing activities | 1,145,955 | 365,979 | (862,501) | |
| Net increase! (decrease) in cash | 290,434 | 150,630 | 37,030 | |
| Cash and cash equivalents at beginning of year | 195,087 | 44,457 | 7,427 | |
| Cash and cash equivalents at end of year | 485,522 | 195,087 | 44,457 |
The Continuing Obligations allow the Company to incorporate by reference information in this Information Memorandum that has been previously filed with the Oslo Stock Exchange or the Norwegian Financial Supervisory Authority in other documents. The Annual Financial Statements for the Group as of and for the years ended 31 December 2016, 2015 and 2014, the audit reports in respect of the Annual Financial Statements and the Interim Financial Statements for the Group as of and for the nine months ended 30 September 2017 and 2016 is by this reference incorporated as a part of this Information Memorandum. Accordingly, this Information Memorandum is to be read in conjunction with these documents. The Annual Financial Statements and the related audit reports are available at www.akerbp.com/en/investor / reports/ quarterly-and-annual-reports/ .
The information incorporated by reference in this Information Memorandum should be read in connection with the following cross-reference table. References in the table to "Annex" and "Items" are references to the disclosure requirements as set forth in the Continuing Obligations by reference to such Annex (and Item therein) of Commission Regulation (EC) no. 80912004 implementing Directive 2003/71/EC of the European Parliament and of the Council of 4 November 2003 regarding information contained in prospectuses as well as the format, incorporation by reference and publication of such prospectuses and dissemination of advertisements, which pursuant to the Continuing Obligations apply correspondingly to information memorandums such as this Information Memorandum.
| Minimum Disclosure Requirement for Prospectuses (Annex I) | Reference Document | Page of Reference Document |
|
|---|---|---|---|
| Item 16.4 | A statement as to whether or not the issuer complies with its country of incorporation's corporate governance regimets); and in the event of non-compliance a statement to that effect with an explanation regarding non-compliance. |
2016 Annual Report | Page 49-59 |
| Item 20.1 | Audited historical financial information covering the latest three financial years, and the audit report in respect of each year prepared according to Regulation (EC) No 1606/2002. |
2016 Annual Report 2015 Annual Report 2014 Annual Report |
Page 63- 113 Page 61-111 Page 84-139 |
| Item 20.4.1 | A statement that the historical financial information has been audited. If audit reports on the historical financial information have been refused by the statutory auditors or if they contain qualifications or disclaimers, such refusal or such qualifications or disclaimers must be reproduced in full and the reasons given. |
2016 Annual Report 2015 Annual Report 2014 Annual Report |
Page 155-116 Page 112- 113 Page 140-141 |
| Item 20.6.1 | The issuer's published quarterly information since the date of its last audited financial statements. The interim report is unaudited and has not been reviewed by the Company's auditor. |
3'd Quarter Report 2017 |
Page 1-32 |
| ESMA CESR recom mendations item 133 |
Competent persons report. The Company's Annual Statement of Reserves, published on Oslo Børs 16 March 2017 is hereby incorporated by reference. The report is available at: |
Annual Statement of Reserves for 2016 |
http://www.newsweb.no/newsweb/search.do?messageld=422817
For twelve months from the date of this Information Memorandum, copies of the following documents will be available for inspection at the Company's registered office during normal business hours from Monday through Friday each week (except public holidays):
The Group's financial statements as of and for the years ending 31 December 2016, 2015 and 2014, and the related auditor reports thereto.
The Company's interim financial statements as of and for the three and six months ended 30 June 2016 and 2017.
Capitalised terms used throughout this Information Memorandum shall have the meaning ascribed to such terms as set out below, unless the context require otherwise.
| AGR | AGR petroleum services. |
|---|---|
| Aker BP | Aker BP ASA, reg. no. 989 795 848. |
| Annual Financial Statements | The audited historical consolidated financial statements for the Group as of |
| and for the years ended 31 December 2016,2015 and 2014, prepared under IFRS. |
|
| APA | Awards in Predefined Areas. |
| ARO | Asset retirement obligations. |
| boe | Barrels of oil equivalent. |
| boepd | Barrels of oil equivalent per day. |
| Effective Date | 1 January 2017. |
| Hess Norge | Hess Norge AS, reg. no. 930459321. |
| Company | Aker BP ASA. |
| Continuing Obligations | Continuing Obligations for Stock Exchange Listed Companies. |
| Corporate Governance Code | The Norwegian Corporate Governance Code of 30 October 2014. |
| E&P | Exploration and production. |
| EC Regulation 809/2004 | The Commission Regulation (EC) no. 809/2004 implementing the Prospectus |
| Directive and the format, incorporation by reference and publication of | |
| prospectuses and dissemination of advertisements, as amended. |
|
| FPSO | Floating Production Storage and Offloading. |
| Group | The Company together with its consolidated subsidiaries. |
| GTA | The Norwegian General Tax Act of 199. |
| HSE | Health, safety and environment. |
| IAS | International Accounting Standards. |
| IFRS | International Financial Reporting Standards as adopted by the EU. |
| Interim Financial Statements | The unaudited historical financial statements for the Group as of and for |
| the six months ended 30 June 2016 and 2015. | |
| IEA. | International Energy Agency. |
| ISIN | International Securities Identification Number. |
| JOA | Joint operating agreements. |
| Management | The members of the Company's executive Management. |
| MoF MoL |
Ministry of Finance. |
| Ministry of Labour. Ministry of Petroleum and Energy. |
|
| MPE M&A |
Mergers and acquisitions. |
| NCS | Norwegian Continental Shelf. |
| NEA | Norwegian Environmental Agency. |
| NGAAP | Norwegian generally accepted accounting principles. |
| NGL | Natural gas liquids. |
| NOK Bond | The NOK Senior Unsecured Bond. |
| Norwegian Securities Trading Act | The Norwegian Securities Trading Act of 29 2007 no. 75, as amended. |
| NPD | Norwegian Petroleum Directorate. |
| OECD | Organization for Economic Co-operation and Development. |
| OPEC | Organisation of the Petroleum Exporting Countries. |
| Oslo Stock Exchange | Oslo Børs (a stock exchange operated by Oslo Børs ASA). |
| OTO | Oil Taxation Office. |
| p.a | per annum. |
| PDO | Plan for Development and Operations. |
| PIO | Plan for Installation and Operation, |
| PPA | Purchase price allocation. |
| PRMS | Petroleum Resources Management System. |
| Prospectus Directive | Directive 2003171 /EC of the European Parliament and the Council of 4 |
| November 2003, as amended, regarding information contained in | |
| prospectuses. | |
| PSA | Petroleum Safety Authority. |
| PTA | Petroleum Tax Act. |
| RBL Facility | Aker BP's senior secured credit facility agreement with DnB Bank ASA, |
| Nordea Bank AB (publ.), Investment Banking Skandinaviska Enskilda Banken | |
| AB (publ.) and BNP Paribas dated 8 July 2014, as amended at the latest 16 |
| August 2017. | |
|---|---|
| Relevant Member State | Each member state of the EEA which has implemented the Prospectus |
| Directive. | |
| Securities Trading Act | The Norwegian Securities Trading Act of 27 June 2007 no. 75. |
| Seller | Hess Norway Investments Limited |
| Shares | The shares of the Company, each with a nominal value of NOK 1.00. |
| SPA | The share purchase agreement entered into on 24 October 2017 between |
| Hess Norway Investments Limited, Hess Corporation and Aker BP ASA | |
| SPE | Society of Petroleum Engineer. |
| Transaction | The acquisition by the Company of Hess Norge. |
| UKCS | United Kingdom Continental Shelf. |
| US HY Bond | The US High Yield Bond. |
| UOP | Unit of production method. |
| VPS | The Norwegian Central Securities Depository (Nw. Verdipapirsentralen). |
| YTD | Year to date.opec |
APPENDIX A-INDEPENDENT PRACTITIONERS ASSURANCE REPORT ON THE COMPILATION OF PRO FORMA FINANCIAL INFORMATION INCLUDED IN AN INFORMATION MEMORANDUM
KPMGAS P.O. Box 7000 Majorstuen Sørkedalsveien 6 N-0306 Oslo
Telephone +47 04063 Fax +47 22 60 96 01 Enterprise 935174627 MVA Internet www.kpmg.no
In accordance with the requirements in section 3.5.2.6 of the 'Continuing Obligations of Stock Exchange Listed Companies" issued by The Oslo Stock Exchange (Continuing Obligations) we have completed our assurance engagement to report on the compilation of pro forma financial information of Aker BP ASA (the "Company"). The pro forma financial information consists of the unaudited pro forma condensed consolidated statement of financial position and income statement as at and for the year ended 31 December 2016, and related notes as set out in section 9 of the Information Memorandum dated 1 December 2017 (the "Information Memorandum") issued by the Company. The applicable criteria on the basis of which management of the Company has compiled the pro forma financial information are specified in EU Commission Regulation (EC) No 809/2004 which is incorporated in section 7-13 of the Securities Trading Act (Norway) and as described in the Pro Forma Financial Information in section 9 of the Information Memorandum.
The pro forma financial information has been compiled by management of the Company to illustrate the impact of the transactions set out in section 4 and section 9 of the Information Memorandum on the Company's financial position as at 31 December 2016 as if the transactions had taken place at 31 December 2016, and on the Company's financial performance for the year ended 31 December 2016 as if the transactions had taken place at 1 January 2016. As part of this process, information about the Company's, BP Norge AS's and Hess Norge AS's financial position and performance has been extracted by management from the applicable annual financial statements as at and for the year ended 31 December 2016.
The Company's management is responsible for compiling the pro forma financial information on the basis of EU Commission Regulation (EC) No 809/2004 as required by the Continuing Obligations.
Our responsibility is to express an opinion as required by Annex II, item 7 of EU Commission Regulation (EC) No 809/2004 which is incorporated in the Securities Trading Act (Norway), about whether the pro forma financial information has been properly compiled, by management of the Company, on the basis described in the Basis of Presentation to the unaudited pro forma condensed consolidated statement of financial position and income statement information and that basis is consistent with the accounting policies of the Company.
We conducted our engagement in accordance with International Standard on Assurance Engagements (ISAE) 3420, Assurance Engagements to Report on the Compilation of Pro Forma Financial Information Included in a Prospectus, issued by the International Auditing and Assurance Standards Board. This standard requires that the practitioner comply with ethical requirements and plan and perform procedures to obtain reasonable assurance about whether management of the Company has compiled the pro forma financial information on the basis described in the basis of presentation.
KPMG AS. a Norwegi,ln limited liability company and member firm cf the KPMG network of Independent member firms affiliated with KPMG tnternational Cooperative ("KPMG mternatlonal"]. 3 Swiss entity.
Statsacturiserte revrsorer. medlemmer av Den norske Revisorforening Finnsnes Molde Tromsø
| Offfcesm: | |||
|---|---|---|---|
| Oslo | Hamar | Skien | Trondheim |
| Alta | Haugesund | Sandefjord | Tynset |
| Arendal | KIlarvik | Sa ml l\l~SSJ(,)l~ n | TønsLlerg |
| Bergen | Knsttansand | Stavanger | Ålesund |
| Bode | Larvik | Stord | |
| Elverum | MOIRana | Straume | |
For purposes of this engagement, we are not responsible for updating or reissuing any reports or opinions on any historical financial information used in compiling the pro forma financial information, nor have we, in the course of this engagement, performed an audit or review of the financial information, including any adjustments made to conform accounting policies, or assumptions used in compiling the pro forma financial information. Our work has consisted primarily of comparing the underlying historical financial information used to combine the pro forma financial information to source documentation, assessing documentation supporting any pro forma and other adjustments and discussing the pro forma information with management of the Company.
The purpose of pro forma financial information included in an Information Memorandum is solely to illustrate the impact of significant events or transactions on unadjusted financial information of the Company as if the events had occurred or the transactions had been undertaken at an earlier date selected for purposes of the illustration. Accordingly, we do not provide any assurance that the actual outcome of the transactions if the transactions had taken place at 31 December 2016 and at 1 January 2016, would have been as presented.
A reasonable assurance engagement to report on whether the pro forma financial information has been compiled on the basis of the applicable criteria involves performing procedures to assess whether the applicable criteria used by management of the Company in the compilation of the pro forma financial information provide a reasonable basis for presenting the significant effects directly attributable to the events or transactions, and to obtain sufficient appropriate evidence about whether:
The procedures selected depend on the practitioner's judgment, having regard to the practitioner's understanding of the nature of the company, the events or transactions in respect of which the pro forma financial information has been compiled, and other relevant engagement circumstances.
The engagement also involves evaluating the overall presentation of the pro forma financial information.
We believe that the evidence we have obtained is sufficient and appropriate to provide a basis for our opinion.
In our opinion:
This report has been prepared solely in connection with the filing of the Company's Information Memorandum required by Oslo Stock Exchange's Continuing Obligations of Stock Exchange Listed Companies section 3.5. This report is not appropriate for any other jurisdiction or purpose other than for the transaction described in section 4 of the Information Memorandum.
KPMG AS Oslo, 1 December 2017
Mona Irene Larsen State Authorised Public Accountant (Norway)
| Enheten | |
|---|---|
| Organisasjonsnummer: | 981 355 210 |
| Organisasjonsform: | Aksjeselskap |
| Foretaksnavn: | BP NORGE AS |
| Forretningsadresse: | Oksenøyveien 10 |
| 1366 LYSAKER | |
| Regnskapsår | |
| Årsregnskapets periode: | 01.01.2016 - 31.12.2016 |
| Konsern | |
| Morselskap i konsern: | Nei |
| Regnskapsregler | |
| Regler for små foretak benyttet: | Nei |
| Benyttet ved utarbeidelsen av årsregnskapet til selskapet: | Regnskapslovens alminnelige regler |
| Årsregnskapet fastsatt av kompetent organ | |
| Bekreftet av representant for selskapet: | Hans Lyng |
| Dato for fastsettelse av årsregnskapet: | 29.03.2017 |
| Grunnlag for avgivelse |
År 2016: Årsregnskapet er elektronisk innlevert År 2015: Tall er hentet fra elektronisk innlevert årsregnskap fra 2016
Det er ikke krav til at årsregnskapet m.v. som sendes til Regnskapsregisteret er undertegnet. Kontrollen på at dette er utført ligger hos revisor/enhetens øverste organ. Sikkerheten ivaretas ved at innsender har rolle/rettighet for innsending av årsregnskapet via Altinn, og ved at det bekreftes at årsregnskapet er fastsatt av kompetent organ.
Brønnøysundregistrene, 30.11.2017
| Beløp i: NOK | Note | 2016 | 2015 |
|---|---|---|---|
| RESULTATREGNSKAP | |||
| Inntekter | |||
| Petroleumsinntekt | 2 | 5 191 305 000 | 7 899 328 000 |
| Annen driftsinntekt | 3 | 7 927 684 000 | 35 321 000 |
| Sum inntekter | 13 118 989 000 | 7 934 649 000 | |
| Kostnader | |||
| Endring i mer-/mindreuttak av petroleum | -51 840 000 | -46 724 000 | |
| Lønnskostnad | 5,8 | 847 310 000 | 885 453 000 |
| Avskrivning på varige driftsmidler og immaterielle eiendeler | 2 381 378 000 | 3 107 633 000 | |
| Andre driftskosntader | 5,11 | 356 302 000 | 759 679 000 |
| Transportkostnader | 622 337 000 | 621 963 000 | |
| Produksjonskostnader | 1 339 976 000 | 2 037 468 000 | |
| Fjerning og nedsteninging | 10 | 4 523 470 000 | 1 392 401 000 |
| Sum kostnader | 10 018 933 000 | 8 757 873 000 | |
| Driftsresultat | 3 100 056 000 | -823 224 000 | |
| Finansinntekter og finanskostnader | |||
| Renteinntekt fra foretak i samme konsern | 61 247 000 | 17 601 000 | |
| Annen renteinntekt | 8 316 000 | 2 327 000 | |
| Sum finansinntekter | 69 563 000 | 19 928 000 | |
| Rentekostnad til foretak i samme konsern | 203 495 000 | 344 141 000 | |
| Annen rentekostnad | 12 369 000 | 6 639 000 | |
| Netto valutatap/gevinst | 109 906 000 | -270 144 000 | |
| Sum finanskostnader | 325 770 000 | 80 636 000 | |
| Netto finans | -256 207 000 | -60 708 000 | |
| Ordinært resultat før skattekostnad | 2 843 849 000 | -883 932 000 | |
| Skattekostnad på ordinært resultat | 6 | -3 124 584 000 | -583 306 000 |
| Ordinært resultat etter skattekostnad | 5 968 433 000 | -300 626 000 | |
| Årsresultat | 5 968 433 000 | -300 626 000 |
| Beløp i: NOK | Note | 2016 | 2015 |
|---|---|---|---|
| BALANSE - EIENDELER | |||
| Anleggsmidler | |||
| Immaterielle eiendeler | |||
| Produksjonsrettigheter | 909 904 000 | ||
| Sum immaterielle eiendeler | 909 904 000 | ||
| Varige driftsmidler | |||
| Produksjonsanlegg og rørledning | 19 821 845 000 | ||
| Lete- og evalueringseiendel | 132 672 000 | ||
| Transportmidler, maskiner og inventar | 62 462 000 | ||
| Sum varige driftsmidler | 20 016 979 000 | ||
| Sum anleggsmidler | 0 | 20 926 883 000 | |
| Omløpsmidler | |||
| Varer | |||
| Lager | 271 699 000 | ||
| Sum varer | 271 699 000 | ||
| Fordringer | |||
| Kundefordringer | 69 070 000 | ||
| Andre fordringer | 23 010 000 | ||
| Skatt til gode | 6 | 2 251 714 000 | |
| Mindreuttak av petroleum | 70 544 000 | ||
| Konsernfordringer | 4 | 14 290 302 000 | 2 162 444 000 |
| Sum fordringer | 16 542 016 000 | 2 325 068 000 | |
| Bankinnskudd, kontanter og lignende | |||
| Bankinnskudd, kontanter og lignende | 13 195 000 | ||
| Sum bankinnskudd, kontanter og lignende | 13 195 000 | ||
| Sum omløpsmidler | 16 542 016 000 | 2 609 962 000 | |
| SUM EIENDELER | 16 542 016 000 | 23 536 845 000 |
| Beløp i: NOK | Note | 2016 | 2015 |
|---|---|---|---|
| BALANSE - EGENKAPITAL OG GJELD | |||
| Egenkapital | |||
| Innskutt egenkapital | |||
| Aksjekapital | 7 | 2 200 000 | 2 000 000 |
| Overkurs | 2 874 000 000 | ||
| Sum innskutt egenkapital | 2 200 000 | 2 876 000 000 | |
| Opptjent egenkapital | |||
| Annen egenkapital | 7 | 828 048 000 | |
| Sum opptjent egenkapital | 828 048 000 | ||
| Sum egenkapital | 2 200 000 | 3 704 048 000 | |
| Gjeld | |||
| Langsiktig gjeld | |||
| Pensjonsforpliktelser | 657 428 000 | ||
| Utsatt skatt | 2 443 627 000 | ||
| Avsetning for fjerning og nedstengning | 7 529 252 000 | ||
| Sum avsetninger for forpliktelser | 10 630 307 000 | ||
| Annen langsiktig gjeld | |||
| Langsiktig konserngjeld | 7 500 000 000 | ||
| Sum annen langsiktig gjeld | 7 500 000 000 | ||
| Sum langsiktig gjeld | 0 | 18 130 307 000 | |
| Kortsiktig gjeld | |||
| Betalbar skatt | 6 | 162 705 000 | |
| Skyldige offentlige avgifter | 116 790 000 | ||
| Utbytte | 7 | 16 539 816 000 | |
| Kortsiktig konserngjeld | 55 282 000 | ||
| Annen kortsiktig gjeld | 1 281 431 000 | ||
| Meruttak av petroleum | 86 282 000 | ||
| Sum kortsiktig gjeld | 16 539 816 000 | 1 702 490 000 | |
| Sum gjeld | 16 539 816 000 | 19 832 797 000 | |
| SUM EGENKAPITAL OG GJELD | 16 542 016 000 | 23 536 845 000 |
| Beløp i: NOK | Note | 2016 | 2015 |
|---|---|---|---|
Garantistillelser 120 000 000
| 2. 一边跳过路路 信天 TA ( A STATISTIC TO ) |
|||||
|---|---|---|---|---|---|
| KPMG AS, a Norwington limited facility company and member firm of the KPMG-oglosix of independent member firms afflicted with KPMG international Cooperative ("KPMG jatemational"), a Swiss antey. |
Quip Address |
Ebohraters Finnsnes |
Mrs y Rom Moiria |
Store Slavanne. |
|
| Statesutoriserte revisorer - moditrimor av Oon norske Revisoriorenna | Argudal Bergen Budis Technological and all |
PEGICINE Haucesund Knazick CONTRACTOR NAME |
Skier: Sandefierd Saminessager and the property of the con- |
3 readward irondheim Evnset Bally and the state and |
| Overskuddet for BPN AS dekkes inn slik: | |
|---|---|
| NOK 1000 | |
| Resultat | 5968433 |
| Avsatt utbytte | 16 539 816 |
| Dekkes inn av annen egenkapital | 10 571 383 |
| NOK 1000 | Noter | 2016 | 2015 |
|---|---|---|---|
| Driftsinntekter | |||
| Petroleumsinntekter | $\overline{2}$ | 5 191 305 | 7899328 |
| 3 | 7927684 | 35 321 | |
| Annen driftsinntekt | 13 118 989 | 7 934 649 | |
| Sum driftsinntekter | |||
| Driftskostnader | $-51840$ | $-46724$ | |
| Endring i mer-/mindreuttak av petroleum | |||
| Transportkostnader | 622 337 | 621963 | |
| Lønnskostnader | 5,8 | 847310 | 885 453 |
| Avskrivninger | 2 3 8 1 3 7 8 | 3 107 633 | |
| Produksjonskostnader | 1 339 976 | 2 037 468 | |
| Andre driftskostnader | 5, 11 | 356 302 | 759 679 |
| Fjerning og nedstengning | 10 | 4 523 470 | 1 392 401 |
| Sum driftskostnader | 10018933 | 8757873 | |
| Driftsresultat | 3 100 056 | -823 224 | |
| Finansinntekter og finanskostnader | 61 247 | 17601 | |
| Renter fra konsemselskap | 8316 | 2 3 2 7 | |
| Annen renteinntekt | $-203495$ | $-344$ 141 | |
| Renter til konsernselskap | |||
| Annen rentekostnad | $-12369$ | $-6638$ | |
| Netto valutatap/gevinst the contract of the company of the contract of the con- |
$-109906$ | 270 144 | |
| Netto finansielle poster | $-256207$ | $-60708$ | |
| Ordinært resultat før skattekostnad | 2 843 849 | -883 933 | |
| Skattckostnad | 6 | -3 124 584 | -583 306 |
| Årsresultat | 5968433 | -300 627 | |
| NOK 1 000 | Noter | 2016 | 2015 COL |
|---|---|---|---|
| Eiendeler | |||
| Anleggsmidler | |||
| Immaterielle eiendeler | |||
| Produksjonsrettigheter | $\Omega$ | 909 904 | |
| Varige driftsmidler | |||
| Produksjonsanlegg og rørledning | 0 | 19821845 | |
| Lete- og evalueringseiendel | $\Omega$ | 132 672 | |
| Transportmidler, maskiner og inventar | 0 | 62 462 | |
| Sum anleggsmidler | $\theta$ OF SHOP |
20 926 883 | |
| Omløpsmidler | |||
| Lager | $\theta$ | 271 699 | |
| Fordringer | |||
| Kundefordringer | 0 | 69 070 | |
| Fordringer på konsernselskap | 4 | 14 290 302 | 2 162 444 |
| Skatt til gode | 6 | 2 2 5 1 7 1 4 | $\Omega$ |
| Andre fordringer | 0 | 23 010 | |
| Mindreuttak av petroleum | $\Omega$ | 70 544 | |
| Bankinnskudd | 0 | 13 195 $\cdots$ |
|
| Sum omløpsmidler | 16 542 016 | 2 609 962 | |
| Sum eiendeler | 16 542 016 | 23 536 845 |
| NOK 1 000 | Noter | 2016 | 2015 |
|---|---|---|---|
| Egenkapital og gjeld | |||
| Egenkapital | |||
| Innskutt egenkapital | |||
| Aksjekapital | 7 | 2 2 0 0 | 2 000 |
| Overkurs | $\ddot{\Omega}$ | 2 874 000 | |
| Opptjent egenkapital | |||
| Annen egenkapital | 7 | 0 | 828 048 |
| Sum egenkapital | 2 2 0 0 | 3704048 | |
| Gjeld | |||
| Avsetning for forpliktelser | |||
| Pensjonsforpliktelse | 0 | 657428 | |
| Utsatt skatt | 6 | 0 | 2 443 627 |
| Avsetning for fjerning og nedstengning | 0 | 7 5 29 2 5 2 | |
| Sum avsetning for forpliktelser | 0 | 10 630 307 | |
| Annen langsiktig gjeld | |||
| Gjeld til konsemselskap | O | 7 500 000 | |
| Sum annen langsiktig gjeld | 0 | 7 500 000 | |
| Kortsiktig gjeld | |||
| Skyldige offentlige avgifter | $\bf{0}$ | 116 790 | |
| Betalbar skatt | 6 | $\mathbf{0}$ | 162705 |
| Utbytte | $\overline{7}$ | 16 539 816 | $\theta$ |
| Gjeld til konsernselskap | $\theta$ | 55 28 2 | |
| Annen kortsiktig gjeld | 0 | 1 281 431 | |
| Meruttak av petroleum | $\theta$ | 86 28 2 | |
| Sum kortsiktig gjeld | 16 539 816 | 1702490 | |
| Sum egenkapital og gjeld | 16 542 016 | 23 536 845 |
Årsregnskap regnskapsåret 2016 for 981355210
| NOK 1000 | 2016 | 2015 |
|---|---|---|
| Kontantstrøm fra operasjonelle aktiviteter | ||
| 2843849 | -883 933 | |
| Ordinært resultat før skattekostnad | 39 897 | $-50140$ |
| Periodens betalte skatt | $-7262275$ | $\Omega$ |
| Gevinst yed salg av virksomhet | 2 381 378 | 3 107 633 |
| Avskrivninger og nedskrivninger | 4 5 2 3 4 7 0 | 1 392 401 |
| Fjernings- og nedstengningskostnader | 1376 108 | 586 377 |
| Endring i kortsiktige fordringer og lager | 34 085 | $-294703$ |
| Endringer i kortsiktig gjeld | $-697792$ | 205 216 |
| Endring i andre tidsavgrensningsposter | $-587226$ | $-811041$ |
| Faktiske fjernings- og nedstengingskostnader | ||
| Netto kontantstrøm fra operasjonelle aktiviteter | 2 651 495 | 3 251 810 |
| Kontantstrøm til investeringsaktiviteter | ||
| Utbetalinger ved kjøp av varige driftsmidler | $-159822$ | $-740.759$ |
| CONTRACTOR CONTRACTOR Netto kontantstrøm til investeringsaktiviteter |
$-159822$ | $-740.759$ |
| Kontantstrøm til finansieringsaktiviteter | ||
| $-7500000$ | $-2,500,000$ | |
| Nedbetaling av langsiktig gjeld | -3 650 000 | $\circ$ |
| Utbetaling av utbytte | 10 519 536 | $\theta$ |
| Tilført egenkapital Overført eierskap av bankkontoer |
$-1874404$ | $\theta$ |
| Netto kontantstrøm til finansieringsaktiviteter | $-2504868$ | -2 500 000 |
| Netto endring i kontanter og kontantekvivalenter for perioden | $-13195$ | 11 052 |
| Kontanter og kontantekvivalenter 1.1. | 13 195 | 2 1 4 3 |
| $V_{\text{subturb}}$ or $\omega$ boutantal vivalenter $31.12$ . | 0 | 13 195 |
| and the state of a second a field | Volum . STATE BERRIER IN 1.11111111111111111111111111111111111 |
NOK 1000 the companies and 20 0.0.2. |
|---|---|---|
| Ráolic | 9974 Tusen fat | 3 572 308 |
| Vålgass | 1630 Tusen fat | 305 178 |
| Gass THE R. P. LEWIS CO., LANSING MICH. |
947 545 Tusen SM3 $\sim$ . ASSESSED AND REAL $\sim$ |
1313819 . |
| ARCHIVES | 5 101 305 |
| NOK 1000 a company $-100$ a se casa concert- |
2016 . |
SEP 2012 11: | 2015 $-200 - 200$ |
|---|---|---|---|
| Frakt og tariffinntekter | 35 529 | 33 795 | |
| Gevinst ved virksomhetsoverdragelse | 7 262 275 | o | |
| Gevinst ved avvikling av pensjonsordninger | 625 028 | Ð | |
| Andre inntekter | 4852 --------- |
. | 1 5 2 6 |
| -------------- a as successive? CONTRACTOR The course of the competition of the Sum andre driftsinntekter the company of the control of the control of the |
7927684 as were find that the $\sim$ |
$\sim$ |
35 321 CONTRACTOR |
| 2016 | 2015 | ||||||
|---|---|---|---|---|---|---|---|
| i mill, kroner -- ---- -- - |
control of the | Baytto sense executive them are to |
Netto a sesse la ÷. |
$\sim$ | Brutto . . |
Nelto STATISTICS |
|
| Lonnskostnader | 1464 | 665 | 1374 | 623 | |||
| Pensjonskostnader | 192 | 87 | 357 | 162 | |||
| Arbeidsgiveravgift | 209 | 95 | $\sim$ CONTRACTOR |
221 COL |
100 1.11111111111111111111111111111111111 |
||
| Totalt | . $\frac{1}{2} \left( \frac{1}{2} \right) \left( \frac{1}{2} \right)$ |
. STATE OFFICE |
and the said --- 865 STATE OF 1.11 |
$-11.1$ 847 STATE |
STATISTICS | 1952 | 885 HOLLYWING |
| Gjennomsnittlig antall årsverk | 862 | 857 |
| i mill. kroner | 2016 11.77 ------ $\sim$ |
2015 $\sim$ |
|||
|---|---|---|---|---|---|
| an a way officed it. Lenn og bonus |
1111 11 | $\sim$ | $-0.11$ | 3.1 | 3,4 |
| *Annen godigiørelse | ٠ | 7.0 . |
0,6 | ||
| $\sim$ Totalt |
10,1 ____ |
4.0 and a support |
| NOK 1 000 | 2016 | 2015 | |||||
|---|---|---|---|---|---|---|---|
| Spesifikasjon av grunnlag for utsatt skatt: | |||||||
| Anleggsmidler | 0 | 14 377 443 | |||||
| Fjerningsforpliktelse | ō | $-7446$ 198 | |||||
| Annet | $-983551$ | ||||||
| Grunnlag for selskapsskatt | O. | 5947684 | |||||
| Libenyttet friinntekt | 0 | -4142578 | |||||
| Grunnlag for særskatt | o | 1805106 | |||||
| 25% selskapsskatt | o | 1486 921 | |||||
| 53% særskatt | 0 | 956 706 | |||||
| Sum utsatt skatt | $\Omega$ | 2443627 | |||||
| Ved transaksjonen 1. desember ble balansen for betalbar og utsatt skatt, hortsett fra de gjenværende skattebalansene knyttet til fremførbare underskudd og friinntekt ført mot gevinst ved virksomhetsoverdragelse til morselskap. I perioden etter virksomhetsoverdragelsen er dot kun renter på kjøpet som får skattemessig effekt. Dette blir utelukkende beskattet i 25% skatteregimet. |
|||||||
| Betaloar skatt/skatt til gode i balansen: | |||||||
| Betalbar skatt årets resultat | 14 086 | 162 705 | |||||
| Skatt til gode | $-2265800$ | o | |||||
| Sum betalbar skatt/skatt til gode | $-2251714$ | 162 705 | |||||
| Årets skattekostnad fremkommer slik: | |||||||
| Betalbar skatt årets resultat | 14 086 | 31931 | |||||
| Betalbar skatt relatert til overføringen til Aker BP | $-132818$ | $\Omega$ | |||||
| Endring utsatt skatt | 3 005 852 | $-615236$ | |||||
| Skattekostnad | 3 124 584 | -583 306 | |||||
| Avstemming fra nominell til faktisk skattesats: | |||||||
| Resultat for skattckostnad | 2843849 | -883 933 | |||||
| Marginal skatt (78%) | 2 218 201 | -689 467 | |||||
| Permanente forskjeller knyttet til overføringen til Aker BP | -S 664 575 | 0 | |||||
| Andre permanente forskjeller | 31 355 | 107 698 | |||||
| Ny friinntekt | $-6561$ | $-16009$ | |||||
| Finansresultat til land og andre | 98 856 | $-21119$ 122 863 |
|||||
| Justeringer for tidligere år | 198 139 |
| Egenkapitul Note 7. |
|||||
|---|---|---|---|---|---|
| NOK 1 000 CONTRACTOR |
. | Aksickapital and a change of the control of the |
Overkurs and the property of the fillest |
Annen opptjent EK --------- |
Sum A 10 5 6 6 6 6 7 8 7 8 8 7 8 7 8 7 8 7 8 7 8 8 7 8 7 |
| ALC: YES THEFT Egenkapital 1.1. |
2000 | 2 874 000 | 828 048 | 3 704 048 | |
| Árets endring i egenkapital: Kapitalforhuyelse |
200 | 10 519 336 | 10 519 535 | ||
| L'ibetalt utbytte | -3 650 000 | -3 650 000 | |||
| Arsresultat | 5 968 433 | 5 968 433 | |||
| Avsatt utbytte | THE R. P. LEWIS CO., LANSING MICH. 49-14039-1-120-2 | LEADER COMMERCIAL TRANSPORTATION | -16 539 816 | $-16539816$ | |
| -------------------------------------- Engelsprited 21.12 |
THIRD IS COMMON COMPANY OF A RESIDENCE OF A | 2,200 | 13 393 336 | -13 393 335 | 2 2 0 0 |
| NOK 1000 STATISTICS |
2016 | 2015 |
|---|---|---|
| Verdi av pensjonsmidler | û | 1 797 446 |
| Nåverdi av pålapt pensjonsforpl. inkl. fremtidig lannsvekst | O. | $-2574220$ |
| Uamortisert tap a construction of the contract of the contract of the contract of the contract of the contract of the contract of the contract of the contract of the contract of the contract of the contract of the contract of the contract The R. P. LEWIS |
$^{\circ}$ A service |
232 516 |
| Over-/underdekning pensjonsmidler | $\Omega$ | $-544259$ |
| Arbeidsgiveravgift the the second contract and |
a | $-109.525$ $1000 - 100$ |
| Sum pensjonsforpliktelse . |
a | -653 784 . |
| Pensjonskostnader | ||
| Årets pensjonskostnad fremkommer som følger : | ||
| Năverdi av årets pensjonsopptjening | 165 923 | 238 503 |
| Rentekostnad av pålopt pensjonsforpliktelse. | 61 396 | 72 640 |
| Forventet avkastning på pensjonsmidler | -53 037 | $-54176$ |
| Resultatsforing av camortisert tap/gevinst | 17 530 | 100 513 |
| Sum | 191812 | 357 480 |
| Arbeidsgiveravgift | 23 232 | 34 368 |
| Avvikling av ordningene | $-861428$ | $\sigma$ |
| Utbetaling av tophat | 236 400 | a |
| Årets pensjonskostnad concerned The Committee Contract |
-409 985 | 391 848 . |
| Følgende økonomiske og aktuarmessige forutsetninger er lagt til grunn: | ||
| 2016 | 2015 | |
| Diskonteringsrente pr 30.11.2016 | 2.50% | 2,70% |
| Forventet avkastning på pensjonsmidler | 3,00% | 3,30% |
| Arlig forventet lannsregulering | 2,25% | 2,50% |
| G-regularing | 2,00% | 2,25% |
| Pensionsregulering | 1.25% | 1,50% |
| Selskap | Selskapsforhold | Type transaksjoner | 2016 | 2015 |
|---|---|---|---|---|
| BP Oil International | tilknyttet selskap | Oliesalg | POINT AND REAL PROPERTY -785 679 |
$-250969$ |
| BP Oil International | tilknyttet selskap | NGL salg | $-243099$ | $-270.705$ |
| BP Gas Marketing | tilknyttet selskap | Gass salge | $-1171914$ | $-1803282$ |
| tilknyttet selskap | kjøp av konsulent - og fellestjenester | 488 210 | 255 280 | |
| BP International Ltd | 29 409 | 21043 | ||
| BP Gas Marketing | tilknyttet selskap | kjøp av CO2 kvoter | 63 237 | 48 407 |
| BP EOC Ltd | tilknyttet selskap | kjøp av konsulent - og fellestjenester | 168 940 | 377 056 |
| BP Exploration Operating CO Ltd. | tilknyttet selskap | kjøp av konsulent - og fellestjenester | 89 323 | |
| BP Corporate North America Inc. | tilknyttet selskap | kjøp av konsulent - og fellestjenester | 67170 | |
| BP Shipping Ltd | tilknyttet selskap | leie av bareboat | 98 385 | 92 542 |
| mor | viderefakturering av arealavgift og forsikring. | 83 076 | $\Omega$ | |
| AkerBP ASA Sum andre |
tilknyttet selskap | kjøp av konsulent - og fellestjenester, samt annet | 54356 | 33 492 |
| Enheten | |
|---|---|
| Organisasjonsnummer: | 930 459 321 |
| Organisasjonsform: | Aksjeselskap |
| Foretaksnavn: | HESS NORGE AS |
| Forretningsadresse: | Jåttåvågveien 7 |
| 4020 STAVANGER | |
| Regnskapsår | |
| Årsregnskapets periode: | 01.01.2016 - 31.12.2016 |
| Konsern | |
| Morselskap i konsern: | Nei |
| Regnskapsregler | |
| Regler for små foretak benyttet: | Nei |
| Benyttet ved utarbeidelsen av årsregnskapet til selskapet: | Regnskapslovens alminnelige regler |
| Årsregnskapet fastsatt av kompetent organ | |
| Bekreftet av representant for selskapet: | Kjetil Bringsverd |
| Dato for fastsettelse av årsregnskapet: | 08.06.2017 |
År 2016: Årsregnskapet er elektronisk innlevert År 2015: Tall er hentet fra elektronisk innlevert årsregnskap fra 2016
Det er ikke krav til at årsregnskapet m.v. som sendes til Regnskapsregisteret er undertegnet. Kontrollen på at dette er utført ligger hos revisor/enhetens øverste organ. Sikkerheten ivaretas ved at innsender har rolle/rettighet for innsending av årsregnskapet via Altinn, og ved at det bekreftes at årsregnskapet er fastsatt av kompetent organ.
Brønnøysundregistrene, 04.07.2017
| Beløp i: NOK | Note | 2016 | 2015 |
|---|---|---|---|
| RESULTATREGNSKAP | |||
| Inntekter | |||
| Salgsinntekt | 3 565 117 497 | 4 900 968 890 | |
| Annen driftsinntekt | -136 243 | 26 000 000 | |
| Sum inntekter | 3 564 981 254 | 4 926 968 890 | |
| Kostnader | |||
| Varekostnad | 1 965 821 889 | 2 105 550 741 | |
| Lønnskostnad | 121 594 696 | 147 412 756 | |
| Avskrivning på varige driftsmidler og immaterielle eiendeler | 2 752 807 944 | 6 108 500 309 | |
| Annen driftskostnad | 172 431 239 | 197 629 139 | |
| Sum kostnader | 5 012 655 768 | 8 559 092 945 | |
| Driftsresultat | -1 447 674 513 | -3 632 124 055 | |
| Finansinntekter og finanskostnader | |||
| Annen renteinntekt | 1 936 264 | 6 122 271 | |
| Sum finansinntekter | 1 936 264 | 6 122 271 | |
| Annen rentekostnad | 1 458 150 377 | 1 525 600 498 | |
| Annen finanskostnad | -24 902 461 | -82 158 627 | |
| Sum finanskostnader | 1 433 247 916 | 1 443 441 872 | |
| Netto finans | -1 431 311 652 | -1 437 319 601 | |
| Ordinært resultat før skattekostnad | -2 878 986 165 | -5 069 443 656 | |
| Skattekostnad på ordinært resultat | -1 588 549 065 | -3 175 449 489 | |
| Ordinært resultat etter skattekostnad | -1 290 437 100 | -1 893 994 167 | |
| Årsresultat | -1 290 437 100 | -1 893 994 167 | |
| Årsresultat etter minoritetsinteresser | -1 290 437 100 | -1 893 994 167 | |
| Totalresultat | -1 290 437 100 | -1 893 994 167 |
Overføringer og disponeringer
| Beløp i: NOK | Note | 2016 | 2015 |
|---|---|---|---|
| Overføringer til/fra annen egenkapital | -1 290 437 100 | -1 893 994 167 | |
| Sum overføringer og disponeringer | -1 290 437 100 | -1 893 994 167 |
| Beløp i: NOK | Note | 2016 | 2015 |
|---|---|---|---|
| BALANSE - EIENDELER | |||
| Anleggsmidler | |||
| Immaterielle eiendeler | |||
| Varige driftsmidler | |||
| Maskiner og anlegg | 33 626 391 675 | 37 264 128 810 | |
| Driftsløsøre, inventar, verktøy, kontormaskiner og lignende | 269 937 | 40 948 | |
| Sum varige driftsmidler | 33 626 661 613 | 37 264 169 758 | |
| Finansielle anleggsmidler | |||
| Andre fordringer | 68 534 165 | 100 928 165 | |
| Sum finansielle anleggsmidler | 68 534 165 | 100 928 165 | |
| Sum anleggsmidler | 33 695 195 778 | 37 365 097 923 | |
| Omløpsmidler | |||
| Varer | |||
| Varer | 120 682 634 | 324 863 308 | |
| Sum varer | 120 682 634 | 324 863 308 | |
| Fordringer | |||
| Kundefordringer | 626 702 083 | 279 387 961 | |
| Andre fordringer | 345 858 583 | 497 016 119 | |
| Sum fordringer | 972 560 666 | 776 404 080 | |
| Bankinnskudd, kontanter og lignende | |||
| Bankinnskudd, kontanter og lignende | 485 521 543 | 195 087 142 | |
| Sum bankinnskudd, kontanter og lignende | 485 521 543 | 195 087 142 | |
| Sum omløpsmidler | 1 578 764 843 | 1 296 354 530 | |
| SUM EIENDELER | 35 273 960 620 | 38 661 452 453 |
| Beløp i: NOK | Note | 2016 | 2015 |
|---|---|---|---|
| Egenkapital | |||
| Innskutt egenkapital | |||
| Selskapskapital | 2 400 000 | 2 300 000 | |
| Overkurs | 2 212 278 965 | 2 125 145 000 | |
| Sum innskutt egenkapital | 2 214 678 965 | 2 127 445 000 | |
| Opptjent egenkapital | |||
| Annen egenkapital | 137 965 786 | ||
| Sum opptjent egenkapital | 137 965 786 | ||
| Sum egenkapital | 2 214 678 965 | 2 265 410 786 | |
| Gjeld | |||
| Langsiktig gjeld | |||
| Pensjonsforpliktelser | 6 267 416 | 1 898 941 | |
| Utsatt skatt | 1 041 822 303 | 2 630 269 760 | |
| Andre avsetninger for forpliktelser | 8 630 750 361 | 10 199 972 807 | |
| Sum avsetninger for forpliktelser | 9 678 840 080 | 12 832 141 508 | |
| Annen langsiktig gjeld | |||
| Øvrig langsiktig gjeld | 22 757 980 009 | 22 757 980 011 | |
| Sum annen langsiktig gjeld | 22 757 980 009 | 22 757 980 011 | |
| Sum langsiktig gjeld | 32 436 820 089 | 35 590 121 519 | |
| Kortsiktig gjeld | |||
| Gjeld til kredittinstitusjoner | 93 817 198 | ||
| Leverandørgjeld | 294 632 634 | 493 112 240 | |
| Betalbar skatt | 1 | ||
| Skyldige offentlige avgifter | 2 798 584 | 3 378 742 | |
| Annen kortsiktig gjeld | 325 030 347 | 215 611 967 | |
| Sum kortsiktig gjeld | 622 461 566 | 805 920 148 | |
| Sum gjeld | 33 059 281 655 | 36 396 041 668 | |
| SUM EGENKAPITAL OG GJELD | 35 273 960 620 | 38 661 452 453 |
| Note | 2016 | 2015 | |
|---|---|---|---|
| Operating revenues | |||
| Crude oil sales | 1 | 3,124,852 | 4,103,948 |
| Gas sales | ı | 374,906 | 697,394 |
| Natural gas liquid sales | 1 | 65,359 | 99,627 |
| Other income | (136) | 26,000 | |
| Total operating income | 3,564,981 | 4,926,969 | |
| Operating cost and expenses | |||
| Production and transportation costs | 1,965,822 | 2,106,767 | |
| Exploration costs | (1,217) | ||
| Salaries and benefits | 2 | 121,595 | 147,413 |
| Ordinary depreciation and impairment | 4 | 2,752,808 | 6,108,500 |
| Other operating costs | 172,431 | 197,629 | |
| Total operating costs and expenses | 5,012,656 | 8,559,093 | |
| Income from operations | (1, 447, 675) | (3,632,124) | |
| Financial income and (expenses) | |||
| Interest income | 1,936 | 6,122 | |
| Interest expense | 9,11 | (1, 458, 150) | (1, 525, 600) |
| Foreign exchange gain/ (loss) | 24,991 | 82,290 | |
| Other finance expences | (88) | (132) | |
| Net financial income/ (expenses) | (1,431,312) | (1, 437, 320) | |
| Income before taxes | (2,878,986) | (5,069,444) | |
| Taxes | 6 | (1, 588, 549) | (3, 175, 449) |
| Net income | (1, 290, 437) | (1, 893, 994) | |
| Allocation of profit (loss) | |||
| Allocated to/from retained earnings | 7 | (137, 899) | (1, 893, 994) |
| Allocated to/from share premium | 7 | (1, 152, 538) | |
| Total year end dispositions | (1, 290, 437) | (1, 893, 994) |
| ASSETS | |||
|---|---|---|---|
| Note | 2016 | 2015 | |
| Fixed Assets | |||
| Tangible assets | |||
| Production facilities in operation | 4 | 33,626,392 | 37,264,129 |
| Office equipment and art | 4 | 270 | 41 |
| Total fixed assets | 33,626,662 | 37,264,170 | |
| Financial assets | |||
| Long-term receivables | 68,534 | 100,928 | |
| Total financial assets | 68,534 | 100,928 | |
| Total non current assets | 33,695,196 | 37,365,098 | |
| Current assets | |||
| Spare parts | 120,683 | 324,863 | |
| Receivables | |||
| Underlift | 3 | 72,634 | 135,264 |
| Accounts receivable | 626,702 | 279,388 | |
| Intercompany receivables | 1.065 | ||
| Prepaid expenses and other receivables | 12 | 273,224 | 360,687 |
| Total receivables | 972,561 | 776,404 | |
| Cash and bank deposits | 5 | 485,522 | 195,087 |
| Total current assets | 1,578,765 | 1,296,355 | |
| TOTAL ASSETS | 35,273,961 | 38,661,452 |
| EQUITY AND LIABILITIES | |||
|---|---|---|---|
| Note | 2016 | 2015 | |
| Shareholder's equity | |||
| Paid- | |||
| Capital stock | 7 | 2.400 | 2,300 |
| Share premium | $\overline{7}$ | 2,212,279 | 2,125,145 |
| Total paid- in capital | 2,214,679 | 2,127,445 | |
| Retained earnings | |||
| Other equity | 7 | 137,966 | |
| Total shareholder's equity | 2,214,679 | 2.265,411 | |
| Long-term liabilities | |||
| Long-term provisions | |||
| Deferred income taxes | 6 | 1.041.822 | 2,630,270 |
| Pension liability | 10 | 6,267 | 1,899 |
| Dismantlement provision | 8 | 8,630,750 | 10,199,973 |
| Total long-term provisions | 9,678,840 | 12,832,142 | |
| Other long-term liabilities | |||
| Intercompany debt | 9 | 22,757,980 | 22,757,980 |
| Total other long- term liabilities | 22,757,980 | 22,757,980 | |
| Total long-term liabilities | 32,436,820 | 35,590,122 | |
| Current liabilities | |||
| Accounts payable and accrued liabilities | 294,633 | 493,112 | |
| Bank overdraft | 5 | 93,817 | |
| Intercompany liabilities | 9 | 325,030 | 213,880 |
| Overlift | 3 | 1,732 | |
| Public duties payable | 2,799 | 3,379 | |
| Total current liabilities | 622,462 | 805,920 |
| Note | 2016 | 2015 | |
|---|---|---|---|
| Cash flow from operating activities | |||
| Income before taxes | (2,878,986) | (5,069,444) | |
| Taxes received/ (paid) | 30,422 | ||
| Depreciation, depletion and amortisation | 4 | 2,752,808 | 3,856,967 |
| Impairment | 4 | 2,251,533 | |
| Accretion on dismantlement less payments | (576, 218) | (931, 807) | |
| Net change in long term receivables | 32,394 | (32, 311) | |
| Net change in long term accruals | 4,368 | 925 | |
| Net change in accounts receivable | (347, 314) | 78,798 | |
| Net change in accounts payable | (198, 480) | (168, 628) | |
| Net change in other current accounts and other changes | 464.176 | 203,071 | |
| Net cash flow from operating activities | (747.251) | 219,527 | |
| Cash flow from investing activities Purchase of tangible fixed assets |
4.8 | (108, 270) | (434, 876) |
| Net cash flow from investing activities | (108, 270) | (434, 876) | |
| Cash flow from financing activities | |||
| Proceeds from new intercompany debt | (648, 693) | ||
| Net change in overdraft | 5 | (93, 817) | (206, 773) |
| Proceeds from issuance of equity | $\overline{7}$ | 1,239,773 | 1,221,445 |
| Net cash flow from financing activities | 1,145,955 | 365,979 | |
| Net increase/ (decrease) in cash | 290,434 | 150,630 | |
| Cash and cash equivalents | |||
| at beginning of year | 195,087 | 44,457 | |
| Cash and cash equivalents | 485,522 | 195,087 | |
| at end of year |
| 2016 | 2015 | |
|---|---|---|
| Salaries and wages local employees | 40.038 | 40,736 |
| Salaries and wages expat employees | 36.118 | 61,435 |
| Social Security taxes | 6.302 | 5,744 |
| Pension costs | 5,003 | 4.567 |
| Other | 34,133 | 34,931 |
| Total Calcular and Departes | 121.995 | 147,413 |
| Remanation to the Managing Literator in 2010 was. | Salaries | Other benefits | Total | |
|---|---|---|---|---|
| Martin George Edwards | 4,204 | 4,682 | ||
| Total | 4,204 | 477 | 4.682 |
| Auditor | ||
|---|---|---|
| 2016 | 2015 | |
| Auditors fee | 560 | 634 |
| Other assurance service | ||
| Other non-audit assistance | ||
| Total audit fees | 560 |
| Underlift of crude oil Underift of natural gas liquids |
31.12.2016 70,948 1,686 |
31,12,2015 134,756 508 |
Change (63,808) 1,178 |
|---|---|---|---|
| Underlift of gas Total |
72,634 | 135,264 | (62, 630) |
| Overlift of crude oil | ۰ | 1,707 | (1,707) |
| Overlift of natural gas liquids Overlift of gas |
24 | (24) | |
| Total | 1,732 | (1.732) | |
| Net under/(over)-lift position as per December 31 | 72,634 | 133,533 | (60, 898) |
| $\mathbf{F}$ , and the second second $\mathbf{F}$ | |||
|---|---|---|---|
| In operation | Other | Total fixed assets | |
| Aquisition cost at 01.01.2016 | 55,810,341 | 71,719 | 55,882,060 |
| Additions | 108.270 | ٠ | 108,270 |
| Change in ARO estimate | (992, 970) | (992, 970) | |
| Sales | |||
| Transfers | (230) | 230 | |
| Aquisition cost at 31.12.2016 | 54,925,411 | 71,949 | 54,997,360 |
| Accumulated depreciation and impairment at 01,01,2016 | 18,546,212 | 71.679 | 18,617,891 |
| Ordinary depreciation | 2,752,808 | 2,752,808 | |
| Impairment | |||
| Accumulated depreciation at 31.12.2016 | 21,299,019 | 71,679 | 21,370,698 |
| Net book value as of 31,12,2016 | 33,626,392 | 220 | 33 626 662 |
| Basis for taxes | 2016 | 2015 |
|---|---|---|
| Effective tax rate reconciliation: | ||
| Income before taxes | (2,878,986) | (5,069,444) |
| Marginal tax rate (78%) | (2, 245, 609) | (3,954,166) |
| Tax effect of: | ||
| Permanent differences | 245, 197 | 582,625 |
| Tax value current year uplift | (12, 624) | (51, 917) |
| Interest on taxable loss and uplift carried forward | (104, 978) | (99, 847) |
| Items taxed onshare (25%) | 501,694 | 456,905 |
| Loss carried forward not expected to be utilised | ||
| Effect from change in tax rates | (32.097) | (82.277) |
| Adjustment tax provision and previous years' adjustment | 59,868 | (26, 771) |
| Tax cost | (1,588,549) | (3, 175, 449) |
| Specification of the year's tax cost | ||
| Adjustment tax provision and previous years' adjustments | 60,629 | (15.112) |
| Deferred taxes | (1,649,178) | (3,160,338) |
| Tax cost | (1,588,549) | (3,175,449) |
| Temporary timing differences | 2016 | 2015 |
| Proporties, plant and equipment | 25,363,992 | 26,567,877 |
| Decommissioning and shutdown | (8,630,750) | (10, 199, 973) |
| Pension assets / (liabilities) | (6,267) | (1, 899) |
| Other temporary differences | (32.402) | 37.793 |
| Basis for deferred corporate and special taxes | 16,694,571 | 16,403,798 |
| Future uplift | (177, 651) | (467,995) |
| Uplift carried forward including interest | (7,274,257) | (7,096,365) |
| Special tax loss carried forward including interest | (9, 450, 135) | (7,895,842) |
| Basis for deferred special taxes only | (16,902,043) | (15, 460, 202) |
| Corporate tax loss carried forward including interests | (12, 827, 059) | (8,892,897) |
| Capitalised interests | 935,899 | 1,005,427 |
| Basis for deferred corporate taxes only | (11, 891, 161) | (7,887,470) |
| 13,021,766 | 12,794,963 | |
| Corporate and special tax (78%) | (9,127,103) | (8, 193, 907) |
| Special tax (54/53%) only | (2, 853, 879) | (1,971,867) |
| Corporate tax (24/25 %) only | 1.039 | 1,082 |
| Corporate tax (24/25 %) not expecte to be utilised Deferred tax liabilities 31.12 |
1,041,823 | 2,630,270 |
| Capital Stock |
Share premium |
Retained Earnings |
Total Equity |
|
|---|---|---|---|---|
| Balance 1.1.2016 | 2,300 | 2.125,145 | 137,966 | 2,265,411 |
| Increase of capital | 100 | 1,239,673 | 1,239,773 | |
| Net income | Her | (1,152,471) | (137,966) | (1, 290, 437) |
| Other changes | (67) | (67) | ||
| Balance 31.12.2016 | 2,400 | 2,212,279 | 2,214,679 |
| Facilities and | |||
|---|---|---|---|
| pipelines | Wells | Total | |
| Provision at 1.1.2016 | 2,705,637 | 7,494,336 | 10.199.973 |
| Payments during the year | (112, 434) | (953, 417) | (1,065,852) |
| Unwinding of discounting | 129,871 | 359,728 | 489.599 |
| Change in estimate | (874.229) | (118, 741) | (992.970) |
| Total provision at 31 12 2016 | 1.848.844 | 6.781.906 | 8 630 750 |
| (Amounts in thousands NOK) | Company | 2016 | 2015 |
|---|---|---|---|
| Long term intercompany debt as of 31 December | Hess Capital Ltd. | 18,635,839 | 18,635,839 |
| Long term intercompany debt as of 31 December | Hess (Netherlands) E&P HLDG B V | 4,122,141 | 4,122,141 |
| Expensed interest on intercompany loans | 964,118 | 1,014,735 | |
| Capitalized interst on intercompany loans | |||
| Total interest on intercompany loans | 964,118 | 1,014,735 | |
| Short term intercompany debt | |||
| (Amounts in thousands NOK) | 2016 | 2015 | |
| Short term intercompany debt as of 31 December | 325,030 | 213,880 | |
| Total short term intercompany debt | 325,030 | 213,880 |
| This year pension costs; | ||
|---|---|---|
| (Amounts in thousands NOK) | 2016 | 2015 |
| Company service cost | (5,608) | (5, 155) |
| Interest cost | (564) | (369) |
| Payroll tax expense | (797) | (727) |
| Return on pension plan assets | 547 | 391 |
| Net pension cost | (6, 423) | (5,859) |
| Administration costs | (26) | (25) |
| Recorded settlements of pension | 202 | |
| Recorded changes in estimates | (212) | (190) |
| Accrued for pension scheme for payroll above 12G | (3,001) | |
| This year pension costs | (9, 459) | (6,074) |
| Financial status: | ||
| Earned pension obligations at 31.12. | (19, 485) | (17,511) |
| Estimated effect of future salary increase | (4, 595) | (3,631) |
| National insurance tax expense | (508) | (942) |
| Estimated pension obligations at 31.12. | (24, 588) | (22, 085) |
| Pension plan assets (market value) at 31,12 | 20,481 | 14,459 |
| Unrecognized effects actuarial gains/losses | 840 | 5,727 |
| Accrued for pension scheme for payroll above 12G | (3,001) | |
| Net benefit asset / (debt) | (6,267) | (1, 899) |
| ECONOMICAL ASSUMPTIONS, | ||
|---|---|---|
| Expected return on pension plan assets | 3.6% | 3.3% |
| Discount rate | 2.6% | 27% |
| Expected salary increase | 2.5% | 2.5% |
| Expected increase in "G" | 2.3% | 2.3% |
| Expected pension increase | 0.0% | 0.0% |
| and the control |
| Related party transactions | ||
|---|---|---|
| (Amounts in thousands NOK) | 2016 | 201S |
| Parent Company and other group companies | ||
| Interest income | ||
| Interest expenses | 964.118 | 1,014,735 |
| Purchase of services | (41, 342) | (62, 252) |
| Sale of petroleum products |
| Note 12 - Breakdown of prepaid expenses and other receivables | 2016 | 2015 |
|---|---|---|
| (Amounts in thousands NOK) | ||
| Prepaid expenses | 151.052 | 214,866 |
| Other receivables | 122, 173 | 145.821 |
| Total prepaid expenses and other receivables | 273,224 | 360.687 |
| Net Proved Developed and Undeveloped Reserves At December 31, 2014 |
с пюсе он ало Natural Gas liquides (Thousand barrels) |
Natural Gas (Millions MCP) |
|---|---|---|
| Revision of previous estimates | 256,561 | 180,039 |
| (47,070) | 21,128 | |
| Production 2015 | (11, 424) | (9,995) |
| At December 31, 2015 | 198,068 | 191,172 |
| Revision of previous estimates | (15,554) | (22, 517) |
| Production 2016 | (8,795) | (8, 541) |
| At December 31, 2016 | 173,719 | 160,115 |
| Net Proved Developed Reserves | Crude oil and | |
|---|---|---|
| Natural Gas liquides | Natural Gas | |
| (Thousand barrels) | (Millions MCF) | |
| At December 31, 2015 | 97.591 | 84.120 |
| At December 31, 2016 | 79,121 | 71,907 |
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