Notes to the company accounts
As of 31 December 2017, Petoro AS acted as licensee on behalf of the SDFI for interests in 186 production licences and 16 joint ventures for pipelines and terminals, including the company’s management of commercial interests in Mongstad Terminal DA and Vestprosess DA, and the shares in Norsea Gas AS and Norpipe Oil AS. The SDFI is also entitled to potential profits in production licences with net profit agreements. Petoro has the same rights and obligations as other licensees, and manages the SDFI on the NCS on the basis of sound business principles.
Administration of the portfolio is subject to the Regulations on Financial Management in Central Government. Accounts for the portfolio are presented both on the cash basis used by the government and in accordance with the Norwegian Accounting Act. The company maintains separate accounts for all transactions relating to its participating interests, so that revenue and costs from production licences and joint ventures are kept separate from operation of the company. Cash flow from the portfolio is transferred to the central government’s own accounts with Norges Bank. Petoro prepares separate annual accounts for the SDFI, with an overview of the participating interests managed by the company and associated resource accounting.
Accounting principles for the company accounts
The principal difference between the profit based on the Accounting Act and on a cash basis is that the latter includes cash payment for investments and operating expenses. Adjustments are also made for accruals of income and expenses on a cash basis, with a corresponding adjustment to debtors and creditors in the balance sheet. Realised currency loss/gain related to operating expenses and income is classified on the cash basis as operating expenses and income. The accounts based on the Accounting Act present realised currency loss/gain as financial expenses/income, and these items are accordingly not included in the operating profit. Differences between the accounts prepared in accordance with the Accounting Act (NGAAP) and on a cash basis are indicated in the notes below.
The SDFI’s interests in private limited companies and apportioned liability partnerships relating to the production of petroleum are included under the respective items in the income statement and recorded in the balance sheet according to the proportionate consolidation method for the SDFI’s share of income, expenses, assets and liabilities. The same applies to licence interests in oil and gas activities, including pipeline transport, which are not organised as companies.
The SDFI’s participation in Statoil Natural Gas LLC (SNG) is recorded as an investment in an associate and recorded in accordance with the equity method. The SDFI’s share of the equity is recorded in the balance sheet under financial fixed assets and its share of the profit/loss is recorded as operating revenue in the income statement.
Dividend from the shares in Norsea Gas AS and Norpipe Oil AS is recorded as a financial item. In addition, revenue from production licences with net profit agreements (concerns licences awarded in the second licensing round) is recorded as other income.
The functional currency is the Norwegian krone.
Revenue recognition principles
The SDFI records revenue from the production of oil, NGL and gas using the sales method. This means that sales are recorded in the period when the volumes are lifted and sold to the customer.
Revenue from ownership in transport and process facilities is recorded when the service is rendered.
Gas swap and borrowing agreements where settlement takes the form of returning volumes are, as a general rule, accrued using the sales method. At the same time, a provision is made for the associated production costs in the event that the SDFI has lent/swapped gas. When lending gas from the SDFI, the lower of production expense and estimated net present value of the future sales price is capitalised as a pre-paid expense at the date of the loan. Furthermore, the SDFI’s share of location swaps related to the purchase or sale of third-party gas is recorded net as operating revenue. The SDFI’s share of time swaps is recorded gross.
Liabilities arising because too much crude oil has been lifted in relation to the SDFI’s share of the production partnership are valued at production cost, while receivables from the other partners in the production partnerships are valued at the lower of production cost and the estimated present value of the future sales price.
Purchases of third-party gas for resale and gas for inventory are recorded gross as operating expenses. The corresponding revenue is included in sales income.
Purchases and sales between fields and/or transport systems
Internal expenses and revenues are eliminated in purchases and sales between fields and/or transport systems in which the SDFI is both owner and shipper, so that only costs paid to third parties appear as net transport costs.
Transactions in foreign currencies are recorded at the transaction rate. Monetary items in foreign currencies are valued at the exchange rate prevailing on the balance sheet date. Unrealised currency losses and realised currency losses/gains are recorded as financial income or financial expenses.
Classification of assets and liabilities
Assets intended for ownership or use over a longer period are classified as fixed assets. Other assets are classified as current assets. Debtors due within one year are classified as current assets. Similar criteria are applied for classification of current and long-term liabilities.
Research and development
Research and development costs are expensed on a continuous basis. In addition to spending on direct research and development in each joint venture, the operator also charges expenses for general research and development to the partnership in accordance with the extent of exploration, development and operating expenses in the joint venture.
Exploration and development costs
Petoro employs the successful efforts method to record exploration costs for SDFI oil and gas operations. This means that costs related to geological and geophysical surveying are expensed. However, expenses linked to the drilling of exploration wells are recognised in the balance sheet pending evaluation. Such costs are expensed if the evaluation determines that the discovery is not commercially viable. Considerable time can elapse between the drilling of a well and a final development decision. Capitalised exploration well expenses are accordingly assessed quarterly to determine whether sufficient progress is being made in the projects so that the criteria for capitalisation continue to be met. Dry wells or wells where progress is insufficient are expensed.
Expenses linked to development, including wells, platforms and equipment, are capitalised. Costs for operational preparations are expensed on a continuous basis.
Tangible fixed assets
Tangible fixed assets and investments are carried at historical cost with deduction for planned and contingent depreciation. Fixed assets under construction are carried at historical cost.
Fixed assets leased on terms which largely transfer the financial risk and control to the SDFI (financial leasing) are capitalised under tangible fixed assets and the associated lease obligation is recognised as an obligation under long-term interest-bearing debt at the net present value of the lease charges. The fixed asset is subject to planned depreciation, and the obligation is reduced by the lease payment after deduction of calculated interest costs.
The SDFI does not take up loans, and incurs no interest expenses associated with the financing of development projects.
Ordinary depreciation of oil and gas production facilities is calculated for each field and field-dedicated transport system using the unit of production method. This means that the acquisition cost is depreciated in line with the ratio between volume sold during the period and reserves at the start of the period. Investments in wells are depreciated in line with the reserves made available by the wells drilled.
Petoro determines the reserve base for depreciation purposes on the basis of estimated remaining reserves per field, which are adjusted by a factor calculated as the ratio between the Norwegian Petroleum Directorate’s total of low reserves in production and the sum of basis reserves in production. This is done for both oil and gas reserves. This reserve adjustment totalled 77.8 per cent of expected remaining oil reserves in 2017, while the corresponding figure for gas reserves was 88.2 per cent. The reserve estimates are revised annually, and any changes affect only future depreciation expenses.
Ordinary depreciation for onshore facilities and transport systems as well as riser platforms used by multiple fields, is calculated on a straight-line basis over the remaining licence period at 31 December.
Other tangible fixed assets are depreciated on a straight-line basis over their expected economic lifetime.
Intangible fixed assets are carried at their fair value at the time of acquisition. They are depreciated over the expected contract period or their expected economic lifetime, and any impairment charges are deducted.
When the accounts are prepared, tangible fixed assets and intangible assets are reviewed for indications of a decline in value. Oil and gas fields or installations are normally treated as separate entities for the purposes of assessing impairment. Should the recoverable value be lower than the book value, and this decline is not expected to be temporary, the asset is written down to its recoverable value, which is the higher of the asset’s fair value less sales costs and its utility value. The utility value is calculated using discounted cash flows, which are discounted using a discount rate based on the weighted average cost of capital (WACC) calculated for the company.
The impairment charge will be reversed if the conditions for writing down the asset no longer apply.
Expenses related to repair and maintenance are expensed on a continuous basis. Expenses for major replacements and renovations that significantly extend the economic life of the tangible fixed assets are capitalised.
Abandonment and decommissioning expenses
Under the terms of a licence, the authorities can require the licensees to remove offshore installations when their production life comes to an end. The estimated fair value of obligations for decommissioning and removal is recorded in the accounts in the period when the liability arises, normally when wells are drilled and installations are built and ready for use. The obligation is capitalised as part of the acquisition cost of wells and installations, and depreciated therewith. Changes to estimated cessation and decommissioning costs are recorded and capitalised in the same manner and depreciated over the remaining economic life of the assets. The discount rate applied when calculating the fair value of a decommissioning liability is based on the interest rate for Norwegian government bonds with maturity matching that of the decommissioning obligation.
A change in the liability relating to its time value — the effect of the decommissioning date having come one year closer — is recorded as a financial expense.
Inventories of spare parts and operating materials are valued at the lower of acquisition cost according to the FIFO principle, or net realisable value. Spare parts of insignificant value for use in connection with operating oil or gas fields are expensed at the time of acquisition. Spare parts of significant value are recorded as inventory at the time of acquisition and expensed when they are used in operations. Petoro takes a point of departure in the operators’ assessments made as regards which materials should be capitalised and which expensed.
Accounts receivable are recognised at face value in the balance sheet less a provision for expected loss. This provision is based on an individual assessment of each debtor.
Bank deposits include cash, bank deposits and other monetary instruments with a maturity of less than three months at the date of purchase. Cash flows from oil and gas sales are transferred to the state on a daily basis. Booked bank deposits thus include the SDFI’s share of bank deposits in companies with apportioned liability in which the SDFI has an interest, and in which the proportionate consolidation method is used.
Current liabilities are recognised at face value.
The SDFI is exempt from income tax in Norway. The SDFI is registered for value-added tax (VAT) in Norway. Virtually all the SDFI’s sales of oil and gas products from its activity take place outside the geographic scope of Norway’s VAT legislation (continental shelf and exports). The SDFI invoices these sales to the buyer free of tax. At the same time, the SDFI can deduct any VAT incurred on invoiced costs relevant to its activity.
The SDFI is covered by the state’s overall risk management. Financial instruments are used as part of Statoil’s optimisation of gas sales.
Financial instruments are valued according to the lowest value principle, unless stated criteria have been met. Unrealised losses relating to financial instruments are recorded as expenses. Unrealised gains are recorded as income if all the following criteria are met: the instrument is classified as a current asset, is part of a trading portfolio as regards resale, is traded on an exchange, authorised marketplace or similar regulated market abroad, and has diverse ownership and liquidity. Portfolio valuations are used as a basis where this, based on the financial instruments, is considered to be the most sensible approach, and where the portfolio is balanced in volume and time. Eliminations are carried out where legal rights exist to offset unrealised losses and gains, or where deposits/margins that correspond with the market value of the derivatives have been paid and capitalised. Gains are otherwise recognised upon realisation.
Financial instruments that are not current assets follow the valuation rules for fixed assets.
Probable and quantifiable losses are expensed. Contingent assets are not included unless the asset is reasonably certain to be settled.