1. Introduction
The petroleum industry is Norway's largest industry measured in terms of value creation, government revenues, investments and export value and a cornerstone for Norwegian social and economic development for the last decades. Norway is a small player in the global crude market with production covering about two per cent of the global demand. However, Norway is the third largest exporter of natural gas in the world and Norway supplies about 25 per cent of the EU gas demand. In 2022, Norway replaced Russia as the European Union’s (the “ EU”) leading natural gas supplier. Nearly all oil and gas produced on the Norwegian Continental Shelf (“NCS”) is exported, and combined, oil and gas equal about half of the total value of Norwegian export of goods. For this reason, oil and gas represent the most important export commodities for the Norwegian economy. Government income is secured by taxation and direct participation in the petroleum activities.
Macroeconomic indicators for the petroleum sector, 1971-2023:
2. Recent developments and key events on the NCS Russia’s invasion of Ukraine
On 24 February 2022, Russia began a full-scale invasion of Ukraine, initiating a war that has received widespread public condemnation internationally. The invasion has had major consequences for the energy markets, as Russia at the time was the world’s third largest exporter of oil and the world’s second largest exporter of gas. EU relied on Russia for around 40% of its natural gas and 27% of its oil consumption. As a response to the invasion, EU, USA, and several other countries, including Norway, adopted additional sanctions against Russia. The sanctions included a ban on import of Russian oil and gas from the United States government and that the Norwegian government decided to freeze the Norwegian Oil Fund’s investments in Russia. It also led to the EU preparing a plan to make Europe independent from Russian fossil fuels.
In late September 2022, three explosions in the Baltic Sea severely damaged the Nord Stream I and Nord Stream II undersea pipelines built to transport natural gas from Russia to Europe. The pipelines were not active in transporting gas at the time of the explosions, but pressurized gas in the pipelines leaked to the atmosphere as a result.
(Source: www.norskpetroleum.no)
Since production started in 1971, oil and gas have been produced from a total of 120 fields on the NCS. At the end of 2022, 93 fields were in production: 70 in the North Sea, 21 in the Norwegian Sea and 2 in the Barents Sea. In 2022, 1 new field was set in production. Five fields are currently under development. Many of the producing fields are ageing, but some of them still have substantial remaining reserves. Petroleum resources on the NCS have been estimated to 15.8 billion standard cubic metres of oil equivalents. Only around 50 per cent of the total discovered and estimated undiscovered petroleum resources have so far been produced and sold.
Energy prices have risen dramatically, and the importance of energy security has been a key topic on the global agenda. During 2022, the price of natural gas in Europe hit an all-time high. Several European countries and the EU have urged Norway to maintain and increase the supply of oil and gas, to which Norway has responded positively. As Norway already is a large supplier of oil and gas, and the demand for fossil fuels is increasing, Norway is likely to be important in securing energy supply to Europe in the coming years. From 2021 to 2022, the gas supply from the NCS increased with approximately 9 billion Sm3 (8%), and it is expected that the gas supply level in 2023 will be approximately at the same high level as in 2022. For the next few years, total production on the Norwegian shelf is expected to increase somewhat, as the decline in production from
aging fields is expected to be lower than the production from new fields that come on stream.
intended but has also been criticised as being too favourable as the oil price has been high during 2022. One new field was set in production during 2022, being Nova in the North Sea. In addition, Njord restarted production after completing a redevelopment of the field.
(Source: www.norskpetroleum.no).
High number of new PDO’s submitted during 2022
In 2022, 13 Plans for Development and Operations (“ PDOs”) were delivered to the Ministry of Petroleum and Energy (the “ MPE”), as well as several plans for projects where the aim is to increase the production close to existing fields or extend their lifetime.
The exploration activity on the NCS was a little lower in 2022 than in 2021, but at the same level as in 2020. In 2022, 34 exploration wells were spudded, and 12 discoveries were made on the NCS. In the 2022 Awards in Predefined Areas (“APA”) round awarded in January 2023, 25 companies were awarded a total of 47 licenses, consisting of 29 in the North Sea, 16 in the Norwegian Sea and 2 in the Barents Sea. 20 of the production licenses are additional acreage to existing production licenses.
In the National Budget for 2022 it was determined that the 26th licensing round on the NCS will not be held in 2022, and in the National Budget 2023 it was determined that the 26th licensing round will be postponed until 2025. The requirements were introduced in negotiations between the Socialist Left Party (Nwg: Sosialistisk venstreparti) and the Government seeking majority support in the Parliament for approval of the National Budget.
Implementation of a cash-flow based tax regime
(Source: The Shelf in 2022, the Norwegian Petroleum Directorate).
The high number of PDO’s submitted has been driven by the temporary tax regime adopted in 2020. The temporary tax regime was adopted during the early stages of Covid, when the oil price was record-low impacting expected activity levels in the oil and gas industry and consequently also the service industry. The tax regime intended to stimulate activity and to preserve the Norwegian service industry, which employs a significant number of persons. The temporary tax regime allows for immediate deduction of investments in the tax base for special tax, in addition to an uplift of 24 per cent, made pursuant to a PDO/PIO filed before 1 January 2023 (see further details in point 11). The uplift has later been reduced to 17.69% for investments made in 2022 and further to 12.4% for investments made in 2023. Considering the high activity level during 2022, the temporary tax regime can be said to have worked as
Effective from 1 January 2022, the Norwegian petroleum tax system was changed to a cash-flow based system, where the petroleum companies will be entitled to immediately deduct investment costs with a tax value of 71.8%. On the other hand, they will no longer receive any uplift on their investments. The combined effective tax rate remains at 78%. For further details and important transition rules, see section 11 below.
Climate change and energy transition - the “climate lawsuit”
On 22 December 2020, the Norwegian Supreme Court, sitting in plenary, passed its judgement in the “climate lawsuit” raised by Nature and Youth and Greenpeace Nordic against the Norwegian State regarding the validity of the decision to grant production licenses in the Barents Sea in the 23rd licensing round. The appellants argued that the Royal Decree granting the production licenses was invalid, claiming that it was in breach of the environmental protection provision and
certain other provisions of the Norwegian Constitution and the European Convention on Human Rights (the “ECHR”), in addition to suffering from procedural errors.
The Supreme Court unanimously rejected the appeal on the constitutional and ECHR issues, stating that it is up to the Parliament and government to decide by which means environmental goals are to be pursued. On the question of invalidity due to procedural error, a majority vote of eleven justices rejected the appeal, while a minority of four justices found that the climate effect of the grant of production licences was inadequately assessed in the impact analysis and voted for invalidity. Following the Supreme Court ruling, the MPE has in its supplementary White Paper on Energy Policy presented in April 2022 announced that the MPE will assess the climate impact of emissions from both the production and petroleum produced (Scope 3 emissions) as part of the process to approve new field developments. In addition, new development plans presented for approval need to include an assessment of the financial climate risk associated with the development. It is expected that the MPE will consequently update the guidance paper for submitting PDO’s.
In June 2021, the climate activists brought their case against the Norwegian State to the European Court of Human Rights. The European Court of Human Rights (the “ECtHR”) has communicated that the application may be an ‘impact case’, which implies that ECtHR can prioritise processing of the case. In October 2022, the ECtHR communicated that three other pending climate change cases will be processed before the Norwegian climate lawsuit.
Energy transition and new industries
The transition to a carbon neutral society has wide implications across all industries and also fuels the development of new industries.
To succeed with the goal of a carbon neutral society, the capture, utilisation and storage of CO2 (“CCUS”) is required. An important initiative to progress CCUS was the approval of funding for “Longship” in 2020, being a full-chain carbon capture, transportation, and storage project, including the project Northern Lights. Northern Lights is a project which intends to transport captured and liquified CO2 by ship from the Eastern part to the Western part of Norway, and thereafter by pipeline to
an offshore storage location subsea in the North Sea for permanent storage. The development plan for the Northern Lights project, the storage part of the Longship carbon capture and storage project, was approved by the MPE in March 2021 and in 2022.
The MPE has further awarded four permits for injection and storage of CO2 on the NCS, of which three are in the North Sea and one in the Barents Sea.
The permits have been awarded to Northern Lights, to Equinor, one group consisting of Equinor ASA, Horisont Energi AS and Vår Energi AS (Polaris), and another group consisting of Wintershall Dea Norge AS and CapeOmega AS.
In January 2023, the MPE announced that they had received applications for injection and storage of CO2 from six companies, being Aker BP ASA, Altera Infrastructure Group, Horisont Energi AS, Neptune Energy Norge AS, OMV (Norge) AS and Wintershall Dea Norway ASA. An additional area in the North Sea was announced as open for permit applications during February 2023. A joint application by Sval Energi AS, Storegga Geotechnologies Ltd., and Neptune Energy Norge AS was then made late February 2023.
(Source: Illustration CCUS, Gassnova, www.norskpetroleum.no)
Several projects for the electrification of NCS installations are underway, driven partly by the cost of CO2 emissions and the climate targets set by the oil and gas industry and the Climate Act. Today, the fields Troll, Gjøa, Ormen Lange, Valhall, Goliat, Martin Linge and Johan Sverdrup are supplied directly with onshore electricity. In addition, Vega is supplied with onshore electricity through Gjøa, and Hod through Valhall. The plan is that the fields Edvard Grieg, Ivar Aasen, Gina
Krog, Solveig and Hanz will receive power under an areawide solution on the Utsira High in the North Sea, as a part of Johan Sverdrup’s second phase. Further, the fields Duva and Nova is contemplated supplied with onshore electricity through Gjøa. In December 2022, the MPE received plans for increased gas production from Snøhvit and electrification of Hammerfest LNG from Equinor ASA, Petoro AS, TotalEnergies EP Norge AS, Neptune Energy Norge AS and Wintershall Dea Norge AS. The transition to electrification is an important measure to reduce the CO2 emissions from the production of oil and gas.
The plans currently adopted are expected to reduce CO2 emissions with 3.2 million tons per year. Other plans are under development, and if adopted; the CO2 emissions may be reduced with a total of 4.9 million tons, which would entail a reduction of nearly 40 per cent of the total emissions from the petroleum industry in 2019.
Electrification of oil and gas installations on the NCS has become an increasingly debated topic as domestic electricity prices onshore has risen sharply during 2022, and a deficit in domestic renewable electricity production is expected within the next few years.
As a partly related initiative, Equinor has announced their aim to build a large floating offshore wind farm outside of Bergen in 2027, to power the Troll and Oseberg fields. The project requires a special approval by the MPE.
In November 2022, the first turbine in the Hywind Tampen floating offshore wind farms started its power production, delivering power to the Gullfaks A platform in the North Sea. The aim of the project is to replace one third of the gas-fired power with renewable wind power for the Snorre and Gullfaks field. Hywind Tampen is currently the world’s first floating wind farm to power offshore oil and gas platforms. The project is expected to reduce CO2 emissions from the Snorre and Gullfaks fields with more than 200,000 tonnes per year. The project has been supported by Enova and the Business Sector’s NoX Fund by NOK 2.3 billion and NOK 566 million to stimulate technology development with offshore wind and emission reductions.
Additional floating and bottom fixed offshore wind farms are expected to be developed over the next 7 to 10 years. After the opening of the areas Utsira Nord and Sørlige Nordsjø II in 2020, the government has
announced its intention to hold an auction for one 1.5 GW capacity project on Sørlige Nordsjø II and a qualitative award process for the award of three or more projects up to 1.5 GW (in aggregate) on the Utsira Nord area. The award criteria are expected to be announced within the end of first quarter 2023. To what extent these wind farms may be made available for supply of electricity to oil and gas installations remains to be seen.
3. The regulatory framework
The Norwegian Petroleum Act of 1996 (the “Petroleum Act”) sets out the main regulatory framework for petroleum activities on the NCS. The Petroleum Act is based on the principle that all petroleum deposits on the NCS are owned by the Norwegian State, and that the State can grant production licenses allowing others to explore for and produce petroleum. Governmental control is further exercised through the requirement of approvals in all phases of petroleum activities, from gathering of seismic data and exploration drilling, to development, operation and decommissioning of oil installations, as well as approval for the transfer of already granted production licenses. The Petroleum Act is supplemented by other legislations specifically relating to petroleum activities, such as the Petroleum Tax Act of 1975, as well as general legislation relevant to petroleum activities such as the Working Environment Act of 2005 and the Pollution and Waste Act of 1981. In addition, there is a significant volume of secondary regulations concerning different aspects for petroleum activities.
4. The main regulatory bodies and State participation in petroleum activities
The main regulatory body is the MPE, which has authority over most parts of the Petroleum Act including ownership regulations and licensing rounds. Some of these functions are delegated to the Petroleum Directorate. Major development projects and issues of fundamental importance must be approved by the Norwegian Parliament. The Ministry of Finance has authority for petroleum tax matters. The Petroleum Safety Authority is responsible for safety and HSE matters.
The Norwegian State has substantial holdings in production licences on the NCS through the State’s Direct Financial Interest (“ SDFI”). The formal licensee
for the SDFI assets is Petoro AS, a company wholly owned by the State. In addition, the State participates through its ownership interests in Equinor ASA and Gassco AS. The latter is a company wholly owned by the State which is the operator of the comprehensive gas transportation system on the NCS. The responsibility for managing the State’s direct and indirect participation in the petroleum activities through SDFI/Petoro and Equinor lies with the Ministry of Trade, Industry and Fisheries –who also manage the State’s ownership interest in other entities such as DNB, Norsk Hydro and Yara.
5. Petroleum activity requires a production license
Companies wishing to produce petroleum on the NCS must hold a production license, providing certain exclusive rights to perform petroleum activities within the geographical area defined by the production license.
Production licenses can be awarded to existing oil companies on the NCS, or to new entrants that are prequalified to hold such licenses. The general policy is that petroleum activities must be carried out by entities that are able to contribute to the Norwegian petroleum industry beyond just financial participation, and that the activities are carried out in an efficient, competent, and responsible manner. Therefore, license awards and prequalification require that the company can demonstrate sufficient technical, financial and Health, Safety and Environment (“HSE”) skills and resources. The prequalification procedure for new entrants typically takes up to half a year. Guidelines for prequalification are found on the web page of the Petroleum Directorate.
6. Licensing rounds
Production licenses are awarded through licensing rounds. There are two different kinds of licensing rounds on the NCS. There is an annual system of Awards in Predefined Areas (“ APA”) in mature parts of the NCS. The APA rounds were originally intended to ensure that areas close to existing and planned infrastructure are available to the industry before existing infrastructure shuts down. Over time, the APA area has been expanded and today the APA area comprises most of the open, accessible exploration area on the Norwegian continental shelf. In addition to the APA system, ordinary licensing rounds are held - normally every second year (although the current government have stated that no such round will be initiated in this parliamentary term). The ordinary rounds focus on
frontier areas that are less explored and where less existing infrastructure has been built.
The MPE awards production licenses based on the applications submitted. Relevant, objective, nondiscriminatory and announced criteria form the basis for these awards. Applicants can apply individually or as a group.
New production licenses are awarded to a group of companies, that each will hold a participating interest in the license. The license grants the participants exclusive rights to surveys, exploration drilling and production of petroleum within the geographical area covered by the license. The licensees become the owners of the petroleum that is produced, with each licensee being entitled to a portion of the petroleum corresponding to their participating interest in the license.
Production licenses are valid for an initial period (exploration period) that can last for up to ten years. During this period, the work program determined by the license must be carried, typically consisting of geological/geophysical surveys or reprocessing, exploration drilling and/or submittal of a PDO. If all the licensees agree, the production license can be relinquished when the work commitment has been fulfilled. Licensees having satisfied the work commitment can demand that the production license is extended for a period which typically is 30 years but may be up to 50 years in special circumstances.
The production licenses are registered in the Petroleum Registry which is an official and publicly available register that among other records ownership and encumbrances. Production licenses can be mortgaged upon application and approval from the MPE.
7. Plans for Development and Operation (“PDO”)
If the licensees determines that it is commercially viable to develop a discovered field, the development shall be done in a prudent manner. The licensees are responsible for the development of new projects, but the development is subject to approval from the authorities. The approval is provided on the background of a PDO submitted to the MPE for approval. PDO’s for large and/or particularly important projects are presented to Parliament before the MPE’s approval. An important part of the PDO is an impact assessment which is submitted for consultation to various bodies that could
be affected by the specific development. The impact assessment shall assess how the development is expected to affect the environment, fisheries, and society in general. The processing of this assessment and the PDO itself is intended to ensure that the projects are prudent in terms of resource management, and that the consequences for other public interests are acceptable. The impact assessment is compulsory unless the licensees can document that the PDO is covered by a relevant existing impact assessment. The MPE has expressed that the impact assessment shall include an assessment of the financial climate risks associated with the development. This entails an assessment of the economical profitability of the development based on future oil prices in a market/revised policy scenario compliant with the goals of the Paris Agreement. Furthermore, following up on the Supreme Court ruling in 2020 in the “climate lawsuit”, the MPE will as part of its approval process include an assessment of the climate effect of emissions from both production and the use of petroleum produced from the field (scope 3 emissions).
The petroleum activities shall be conducted in a prudent manner to ensure that a high level of HSE can be maintained and developed throughout all phases, in line with the continuous technological and organisational development. The licensees are responsible for pollution without regard for fault. This is referred to as strict liability.
8. Joint Operating Agreements
The license holders form a joint venture that is responsible for the petroleum activities within the license area. The license group is required to enter into a Joint Operating Agreement (“JOA”) which regulates the rights and obligations for the joint venture within the specific license. The JOAs are standardized by a format that the MPE requires all license holders to use. The MPE nominates one of the participants in the license as the operator, which will be responsible for the operational activities authorised by the license. Major decisions are made by the management committee where all license holders are represented and have voting rights according to voting rules set out in the license terms. Normally, a decision is made by the management committee when at least two of the participants that jointly represent at least 50 per cent of the participating interest vote in favour of a proposal.
The participants in the license have joint and several liability for the obligations and liabilities arising out of the license.
9. Licensees are required to provide a Parent Company Guarantee
The Petroleum Act section 10-7 gives the MPE the right, at any time, to demand adequate security for holders of production licenses on the NCS. The authority pursuant to section 10-7 is quite wide with regard to timing and the nature of the security that can be required. However, in practice the MPE requires licensees to provide an unlimited Parent Company Guarantee (“ PCG” ) for the benefit of the Norwegian State to secure all obligations in relation to the petroleum activities. The format and wording of the parent company guarantee is based on a standard template. This standard form is non-negotiable and is kept in a brief format. So far there have been no instances where the guarantee has been used in practice, and there are therefore several issues where the interpretation is unclear. For instance, it is debated whether other participants in a license can draw on the guarantee if another partner in the license defaults on its obligations.
The main policy is that the MPE will require that the parent company guarantee is provided by the ultimate parent company of the licensee. A company is considered a parent company if the company, directly and/or indirectly, owns or controls more than 50 per cent of the licensee. Thus, a company owning and/or controlling less than 50 per cent will normally not be required to issue a PCG. There are examples where the parent company guarantee has been issued by entities within a group that is not the ultimate parent company. For corporate transactions, the current policy of the MPE is to return parent company guarantees if a shareholder ceases to have more than 50 per cent of the shares in the licensee.
10. Decommissioning liability
There is currently no practice or requirement for general decommissioning security arrangements internally between the partners in a license.
11. The Norwegian Petroleum Tax System
The petroleum resources belong to the Norwegian State and the State secures its revenues through taxation, direct participation in the licenses through Petoro and as a shareholder in Equinor. Norway has no additional production sharing or royalty schemes but imposes fees on emission of CO2 and NOX.
As a main rule, the Petroleum Act requires licensees to submit a cessation plan to the MPE two to five years before the licence expires or is relinquished, or before the use of a facility ceases. The cessation plan must have two main parts: an impact assessment and a disposal section. The impact assessment provides an overview of the expected consequences of the disposal for the environment and other factors. The disposal part must include proposals for how cessation of petroleum activities on a field can be accomplished. In addition to the Petroleum Act, the Oslo Paris Convention for the protection of the marine environment of the North- East Atlantic (“ OSPAR”) also governs disposal of facilities. As a general principle under the OSPAR convention, facilities cannot be abandoned on-site.
It follows from the Petroleum Act that a seller of a participating interest in a production license will remain secondary liable for decommissioning costs. The secondary liability applies to the seller’s share of installations existing at the time of the transaction and is a financial obligation to pay the (after tax) cost of the decommissioning if the buyer of the participating license fails to meet its obligations. To protect the seller from such liability it is not uncommon to enter into decommissioning security agreements between the buyer and the seller, depending on the financial solidity of the parties and the amount of decommissioning obligations. In a corporate transaction structured as a sale of a controlling interest in a Norwegian E&P entity, practise has now been established whereby the MPE generally require that the ultimate selling parent company issue a parent company guarantee to the State establishing a comparable secondary liability for decommissioning obligations of the target entity – see more on this in section 13 below.
Companies participating in production and pipeline transportation of petroleum on the NCS, are subject to the special petroleum tax regime with a combined effective tax rate of 78% (the effective tax rate is actually 78.004% but is referred to herein as 78%).
The petroleum tax consists of both the ordinary corporate tax, where the formal corporate tax rate is 22%, and the special petroleum tax, where the rate is 71.8%. However, since a calculated corporate tax may be deducted in the special tax base, the effective corporate tax is only 6.2 percent.
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 to be set off against assessed income for special tax purposes and there are limitations on the right to set off other losses against the general tax base.
Historically, petroleum investments were booked and depreciated over time. In addition, the petroleum companies were entitled to an extra investment deduction item in the special tax base (uplift).
Effective from 1 January 2022, the special petroleum tax is levied on cash flow-based model. In the special tax base, investments in pipeline and production facilities are deductible in the investment year. In the corporate tax basis, investments in pipeline and production facilities are capitalized and depreciated under a straight-line method at a rate of 16 2/3 per cent annually from the year in which the investments take place, i.e., deprecation over 6 years.
The tax value of any losses in the special tax regime will be settled as a tax refund from the State as part of the annual tax assessment. The tax value of losses in the corporate tax must be carried forward (in nominal values).
The licensee will be entitled to tax deductions with regard to exploration and production costs (running expenses, depreciations and uplift) and transportation costs (tariff payments). Financial costs are fully deductible in the corporate tax base. Some of the financial costs may also be allocated to the special tax base pursuant to a specific formula. However, due to the new cash-flow based special tax, the allocation will soon become zero or close to zero.
Norm prices can be imposed when calculating taxable income from the sale of produced petroleum. The Petroleum Price Council (“PPR”) determines the norm price. The Council receives information from and meets with companies before setting the final norm price. This norm price system applies to certain grades of crude oil and NGL. For gas, the actual sales price is used as the tax basis. However, related party transactions may be adjusted by the tax authorities if the gas prices are not in line with the arm’s length principle.
In connection with the transition to the new cash flowbased tax regime, historical tax losses carried forward and unused uplift will be refunded from the State as a part of the tax assessment for the income year 2022.
In 2020, provisional tax changes were made to stimulate investments in the petroleum sector. A key element is that investments booked in 2020 and 2021 were immediately tax deductible in the tax base for special tax, in addition to an uplift of 24 per cent in the year of investment. Such tax treatment will also comprise investments made pursuant to (A) a PDO/PIO filed before 1 January 2023 and (B) approved by the Government after 12 May 2020, but before 1 January 2024 (but not investments made after the year of planned “first oil” as defined in the approved PDO/PIO). However, the uplift was reduced from 24% to 17.69% for investments made in 2022. For 2023, the uplift is further reduced to 12.4% on such investments made in 2023.
Investments comprised by the provisional tax changes are capitalised and depreciated over 6 years in the corporate tax base, as under the ordinary petroleum tax rules.
12. Transactions and change of ownership
Participating interests in Norwegian petroleum licenses are transferrable. The participating interests can (except for some of the older licenses) be sold without the consent of the other license partners, provided that
the compulsory work obligation set out in the license has been fulfilled. Prior to fulfilment of the work obligation the management committee of the license must give its consent to an assignment. There are normally no preemption rights for the other private license partners pursuant to the JOAs, except in some of the older licenses. The Norwegian State/Petoro has a general right of pre-emption, but so far this has to our knowledge not been used in practice. In a scenario with increased focus on securing energy supply to Europe, this provision should be assessed in relation to each individual transaction.
Direct transfer of participating interests is subject to approval by the MPE pursuant to the Petroleum Act. The same applies for share transactions which according to law “may provide decisive control of a licensee possessing a participating interest in a licence”.
The MPE have stated that the wording shall be interpreted broadly, and that approval may be required for transactions where the buyer does not even achieve negative control. Further, it stipulated that any uncertainty with respect to the applicability of the requirement must be discussed with the MPE.
Approval by the Ministry of Finance is also required for the same transactions for tax purposes. The main principle is that transactions should be tax natural. Hence, in asset transactions (direct transfer of participating interests) the tax basis of depreciation and uplift related to the assets are transferred to the buyer (tax continuity). Further, the consideration is not taxed as income for the seller and is, correspondingly, not deductible for the buyer. Losses and unused uplift carried forward will as a rule remain with the seller. Share transactions will normally not trigger Norwegian tax.
Transactions can also trigger other regulatory approvals, such as approval from the MPE for change of operatorship or approval to create pledges over the license interests. The Petroleum Safety Authority can also require that new applications are made with regard to HSE related permits if the transaction changes the basis for existing permits.
It is a general principle that all petroleum activities within a group are conducted through one single legal entity. Therefore, if an existing company buys the shares of another company, the MPE will require that the
businesses are combined into one single legal entity. If the two companies are participants in the same licenses, the MPE may also require that the voting rules are amended.
If a contemplated transaction leads to a company acquiring 100 per cent ownership in a production license, the MPE has in relation to transactions set as a requirement for its approval that the acquiring company divests a part of its participating interest in the relevant license.
13. The government’s current approach to companies exiting the NCS
Up until late 2017, it was possible to achieve a clean exit from the NCS by selling shares in a subsidiary that holds production licenses. For share transactions there was no secondary liability for decommissioning, since a share transaction does not imply a change of the legal entity holding the production license. It was also the government’s policy to return the parent company guarantee when the shares were sold.
As many of the international majors have already exited the NCS or have communicated that they intend to divest, a concern for the government has been whether the new entrants will be able to meet future decommissioning costs. This prompted the government to revisit the policy of granting companies a clean exit., and in November 2016 the MPE sent a letter to the companies to address its new approach to such matters.
As from late 2017, the MPE’s policy have however been that they will consider imposing as a condition to approve the new owner that the selling shareholder undertakes to issue a new parent company guarantee where the seller remains secondary liable for existing decommissioning obligations.
The MPE has developed a standard template for the new guarantee. As a result of this approach, share transactions and asset transactions are now treated more equally in terms of decommissioning obligations. Several questions arise relating to this approach which has yet to be resolved, inter alia whether a payment under the new guarantee should be calculated as an amount pre- or post-tax.
***
Further information regarding Norwegian petroleum activities (including unofficial translations of the model production license and JOA) can be found here:
https://www.norskpetroleum.no/en/
This site is operated by the Ministry of Petroleum and Energy and the Norwegian Petroleum Directorate.
OUR SERVICES
BAHR’s legal team has vast experience of working closely with a number of major players on the Norwegian Continental Shelf. We have a thorough understanding of the legal framework governing the industry. We advise in large transactions and represent companies in legal disputes. We also assist in connection with major development projects. Furthermore, we have comprehensive experience within the regulatory field including extensive government relations. BAHR also has expertise in petroleum taxation, appeals and litigation of tax disputes. We represent several large oil companies in complex tax disputes before the tax assessment administration and the court.
CERTAIN RECENT MATTERS WITHIN THE OIL & GAS SECTOR
• Assisting Aker ASA and Aker BP ASA with the acquisition of Lundin Energy Norway AS.
• Assisting Sval Energi AS with several transforming transactions, including inter alia (i) the acquisition of Spirit Energy Norway AS’s key assets, (ii) the acquisition of Equinor Energy AS’ 19% participating interest in the Martin Linge Unit and Equinor’s entire participating interest in the Greater Ekofisk Area and (iii) the acquisition of and subsequent consolidation with Suncor Energy Norge AS.
• Advise on contract strategy, contract development and negotiations, and project follow
• Assisting INEOS on the sale of the entire Norwegian E&P business to PGNiG Upstream Norway AS.
• Assisting several E&P companies with strategic advice in relation to the development of carbon capture and storage (CCS) solutions, including contractual matters, cooperation agreements and regulatory issues.
• Assisting Norwegian Energy Company ASA with a new subordinated convertible bond.
• Acting as counsel for HitecVision in an international oil and gas arbitration against Tullow Oil.
• Assisting AkerBP with financing agreements, including a USD 3.4 billion corporate revolving credit facility
• Assisting well known oil and gas companies with tax advice, including assistance with disputes with tax authorities
• Acting as counsel to an international oil company in relation to a dispute related to a tie-in agreement on the Norwegian Continental Shelf.
• Assisting managers in connection with the public offering and listing of Vår Energi ASA on Oslo Børs.
• Assisting in relation to a substantial gas price review arbitration
• Assisting Hav Energy AS and Sval Energi AS with the sale and purchase of Sval’s interests in the gas transportation infrastructure Polarled and Gassled.
EDITORIAL COMMITTEE
For more information, please contact:
Stig K. Engelhart
M: +47 47 01 11 12
E: skl@bahr. no
Trond Lingaas
M: +47 92 04 46 74
E: troli@bahr.no
Marius Pilgaard
M: +47 90 68 82 47
E: mapil@bahr.no
Joachim M. Bjerke
M: +47 90 50 57 77
E: jmb@bahr.no
Fanny Bjærke Estensen
M: +47 91 12 11 57
E: faest@bahr.no
Julian Davidsen
M: +47 97 61 91 25
E: judav@bahr.no
This pamphlet contains information in summary form and is therefore intended for general guidance only. It is not intended to be relied upon as legal advice or be a substitute for detailed research or the exercise of professional judgement. Please refer to your advisors for specific advice. BAHR will not accept any responsibility for loss occasioned to any person acting or refraining from action as a result of any material in this newsletter.
