Legal framework of petroleum activity on the Norwegian Continental Shelf

Over the last years there has been a clear shift on the Norwegian Continental Shelf (the NCS) from being dominated by the six or seven largest oil and gas companies in the world (super-majors) to a more varied group of companies today. Some of the super-majors have left the NCS, others have reduced their participation, and we have seen numerous new players entering, backed by both PE-funds and private investors.

We regularly advice newcomers, often with investors or parent companies based abroad. Based on that experience, we often see a need for an increased understanding of the legal framework on the NCS, both prior to and during the establishment of their business here.

Overview of regulations and governing bodies

The Norwegian Petroleum Act of 1996 (the Petroleum Act) establishes the primary regulatory framework for petroleum activities on the NCS. A basic principle set out in the Petroleum Act is that the Norwegian State has the proprietary rights to subsea petroleum deposits and exclusive rights to resource management on the NCS.

The regulatory framework is designed to ensure that the Norwegian State safeguards its ownership interests in the best possible way. Governing bodies oversee the petroleum activities carried out on the NCS and government approvals are required by law in all phases of the activities.

Resource management on the NCS rests with the King in Council (the Government). The general policy is to secure long-term sustainable exploitation of petroleum resources for the benefit of the Norwegian society.

The Ministry of Petroleum and Energy (the MPE) is responsible for regulating and overseeing petroleum activities on the NCS from a resource management perspective, under delegate authority and according to principles set out in the Petroleum Act with underlying regulations. The Petroleum Directorate (the NPD) is a subordinated agency of the MPE and support such tasks. Other central regulatory bodies include the Petroleum Safety Authority (the PSA), overseeing health and safety regulations, and the Norwegian Environment Agency (the NEA), overseeing environmental matters. In addition, the Ministry of Finance (the MoF) and the Petroleum Tax Office regulate and oversee petroleum taxation matters.

The licencing system

Different types of Licenses

Petroleum activities on the NCS are governed by a licensing system set out in the Petroleum Act and managed by the MPE.

According to the Petroleum Act, three types of licenses may be granted for petroleum activities on the NCS: (i) exploration license, (ii) production license and (iii) license to install and operate installations.

An exploration license provides the holder with a non-exclusive right to explore petroleum in a limited area and for a limited period (3 years). The activities allowed under such license are restricted (and do not include exploration drilling). In practice, the applicants are typically seismic service providers proposing to conduct general or specific surveys to map the prospectivity of the survey area. The exploration license does not give any preferential right when production licenses are granted.

A production license gives the licensee an exclusive right to exploration, including exploration drilling, and production of petroleum deposits in the areas covered by the license. The King in Council awards production licenses for an initial period of up to ten years. Typically, specified work obligations must then be completed within defined time limits, after which the licensees are entitled to an extension of the license period. In practice, it is the production license that is relevant to companies wishing to perform exploration and production operations on the NCS.

Production licenses are awarded based on objective, non-discriminatory and published criteria. The most important criteria are relevant technical expertise, adequate financial capacity, geological understanding and experience.

A license to install and operate installations gives the licensee a non-exclusive right to install and operate petroleum facilities. This can typically be pipelines and processing facilities outside an approved field development plan (which again are linked to one or several specific production license(s)).

Award of Licenses

Two different procedures are applied for the award of production licenses. Firstly, in traditional numbered licensing rounds, production licenses are awarded in less mature areas. Numbered licensing rounds are normally announced every second year, after a public consultation process where oil companies can nominate blocks. The MPE awards production licenses to applying companies in a joint venture and appoints an operator based on the applications received and subsequent consultations with the applicants.

Secondly, production licenses are awarded annually by a simplified procedure for awards in predefined areas (APA) in more mature areas. An essential purpose of the APA rounds is to take advantage of existing infrastructure and facilitate rapid development. Therefore, these licenses typically include more strictly defined mandatory work obligations and time limits.

Qualification as a licensee

A pre-qualification system is applied to facilitate license applications from new entrants on the NCS. Pre-qualification assures that license awards are obtainable, but any specific license award or approval of transactions will nevertheless be subject to further review and approval. To qualify as a licensee on the NCS, the licensee must be a Norwegian limited liability company and will need to demonstrate technical petroleum expertise to provide independent contributions to this value creation. At the same time, it is also important that new players possess HSE expertise which helps bolster safety on the NCS.

Licensees on the NCS must have a minimum of expertise in all relevant disciplines in order to be able to analyze, understand and follow up activities in the production licenses. The licensees must have sufficient dedicated capacity and expertise to safeguard their obligations in relation to requirements in the petroleum regulations. An organization in Norway consisting of a minimum of 8-9 personnel employees with technical and HSE expertise will therefore be necessary.

Beyond this minimum expertise, licensees should possess cutting-edge expertise within relevant disciplines in order to contribute to value creation. New entrants are expected to be able to contribute their own technical assessments which challenge and complement the other licensees.

The new entrant must also be able to document its ability to service financial obligations. Among other things, this means that the licensee must have a solid foundation of equity, as well as a reasonable ratio between equity and debt.

Mandatory work obligations

Production licenses are usually awarded subject to specific conditions, particularly mandatory work obligations to be fulfilled by the licensees within defined time limits. The content of imposed work commitments varies, but typically comprise procurement and reprocessing of seismic data, relevant geology studies, and drilling of one or more exploration wells. Drilling commitments may be firm or conditional on specific circumstances. The mandatory work obligations are normally decided following a dialogue between the MPE and the license applicants.

In addition to firm work obligations, licenses may be conditional on certain decisions being made within defined time limits. For example, APA licenses typically have fixed deadlines for the initial, firm work commitments and subsequent decisions to undertake exploration drilling, mature prospects, and decide on field development. If work commitments and decision deadlines are not being met, the production license will lapse.

License duration

A production license is granted for an initial period, generally between six and eight years, but can be up to ten years. Upon completing the mandatory work obligations, the licensee is entitled to an extension of the license period. The extension period will typically be up to 30 years, but may also be up to 50 years. Usually, the extension period is set out in the license document. The time limits in the mandatory work obligations and the duration of the initial license period may be extended upon application to the MPE. In some cases, the MPE may also grant further extensions of the extended license period. However, the licensees have no legal right to be granted such further extensions.

Assignment of participating interests

Transfer of a license or part of a license requires consent from the MPE according to the Petroleum Act section 10-12. The Petroleum Tax Act section 10 also requires either a consent from the MoF or, if certain conditions are fulfilled, a notification to the MoF. The same applies to indirect transfers such as the sale of shares in a licensee or in a controlling shareholder in a licensee, which may provide decisive influence over a licensee. The lower limit for decisive influence is interpreted by the MPE as negative control, i.e. control over 1/3 or more of the votes in a licensee, but has is some cases been interpreted as even lower degree of voting control if the votes de facto gives negative control.

The general criteria for consent according to the Petroleum Act section 10-12 are primarily the same as for the granting of new licenses, in particular related to whether the acquiring party has the necessary technical and financial capacity. It is expressly stated in the Petroleum Act section 10-12 that any approval may be subject to conditions set by the MPE. This also follows from the general right for the MPE to set conditions to the individual decision in the Petroleum Act section 10-18.

According to the Petroleum Tax Act section 10, MoF only have to be notified if the transaction is in accordance with the Petroleum Tax Act Section 10 Regulations.

The Norwegian State has pre-emption rights concerning any total or partial license transfers on the NCS, allowing the State to acquire the relevant license interests at such price and such terms as are agreed between the transacting parties. To our knowledge, the State has never used its pre-emption right, but this has to be confirmed for each transaction. In general, no pre-emption rights apply for licenses other than the State, with the exception of a few older licenses/units where such provisions may still be relevant.

In relation to license interests transferred after 2009, the previous licensee will remain secondarily liable for decommissioning costs according to the Petroleum Act. However, such secondary liability is limited to a proportional share (equaling the sold license interest) of decommissioning costs for facilities that existed at the time of the license transfer and are further limited to the after-tax value of the relevant costs (currently 22 %).

The JOA

Production licenses are awarded on the condition that the licensees enter into a non-negotiable agreement for petroleum activities.

The agreement consists of three parts: (i) Special Provisions that apply to the specific license, (ii) a standard Joint Operating Agreement (the "JOA") (part A) and (iii) a standard Joint Accounting Agreement (part B). The JOA is a standardized document drafted by the MPE and cannot be amended or supplemented without approval from the MPE.

The JOA is interlinked with the production license. The production license regulates the rights and obligations of the license in relation to the State, and the JOA regulates the relationship between the licensees. Together the license participants form an unincorporated joint venture, undertaking the joint activities related to the production license. The license joint venture is exempted from the provisions of the Norwegian Companies Act. It is regulated solely by the JOA and relevant provisions of the production license and the Petroleum Act, with underlying regulations.

The MPE appoints an operator of each license joint venture among the license participants. The operator is in charge of the day-to-day operations of the license joint venture. The authority and obligations of the operator are further detailed in the JOA. The operator acts on a "no gain no loss" basis and represents the license joint venture in discussions with relevant authorities and other third parties. The operator also prepares the basis for decisions by the Management Committee of the license group (the "MC").

The MC consist of one representative of each license participant and is the supreme body of the license joint venture, with powers to decide on matters of any nature relating to the joint venture's activities. The MC passes decisions based on individually stipulated qualified majority rules set out in the Special Provisions of each production license. Certain matters are not subject to a majority decision but must be resolved unanimously by the MC:

• Relinquishment of acreage within the license area or surrender of the production license;
• Decision to reduce the frequency of MC meetings (less often than every third month);
• Matters not included in the agenda for an MC meeting;
• Dismissal of the operator (the operator is not allowed to vote on such matter);
• Changes to the percentages the operator may exceed a budget item with (or incur costs not comprised by a work program);
• Changes to the thresholds for procurements that must be approved by the MC; and
• Adoption of a gas lift and balancing agreement.

The plan for development and operations (the "PDO") of a field to be developed is adopted by a majority resolution, but must subsequently be acceded to by each licensee individually.

In case of a change in the license interests, new voting rules should be considered and proposed by the licensees and approved by the MPE. If the licensees cannot agree, the MPE determines amended voting rules.

Each licensee shall hold an undivided interest (ideal share equivalent to the participating interest) in all capital assets and rights of any kind acquired by the operator on behalf of the joint venture. This includes petroleum that has been produced, but not yet disposed of (lifted) by any party. The licensees are primarily liable to each other on a pro-rata basis, secondarily jointly and severally liable for all obligations arising from the joint venture's activities. This applies irrespective of liability towards third parties. Each licensee is responsible for its share of the area fee and direct taxes. The licensees are obliged to provide sufficient funds to cover all expenses relating to the joint venture activities. Each licensee's amount to be contributed shall be calculated following the participating interest when the payment is made. Funds are contributed based on cash calls from the operator.

If a licensee fails to comply with a payment obligation, the unpaid amounts shall be advanced by the non-defaulting licensees according to their participating interest. The non-defaulting licensees may cover the pending advance by acquiring the defaulting licensee's share of produced petroleum. The defaulting licensee shall also be charged a penal interest. If the default persists, the defaulting licensee loses its right to vote in the MC and access to data and information. Eventually, the non-defaulting licensees may demand that the defaulting licensee assigns its participating interest to them.

Until the mandatory work commitment under the production license has been carried out, any assignment of participating interests in a production license is subject to the consent of the MC.

A licensee may withdraw from the JOA when the mandatory work obligation described in the production license has been carried out. However, if a licensee has acceded to a PDO, it may only withdraw when the MPE has determined that the plan is completed.

According to the applicable JOA, any disputes arising in connection with the JOA shall be settled by ordinary Norwegian courts of law.

Unitization and/or coordination

Petroleum deposits may extend over more than one license area and hence pertain to different license groups. In that case, the Petroleum Act requires the affected license groups to seek to agree on principles for joint development of such petroleum deposit and the apportionment of the deposit between the license groups. Similar requirements apply to separate petroleum deposits, where joint petroleum activities are viewed as more efficient.

In practice, license groups with shared resources are required to form a unit to develop and produce the unitized license area or structure, governed by a Unitization and Unit Operating Agreement (a "UOA"). Under the UOA, the licensees form a new unit joint venture, with all affected license joint ventures as unit participants.

The UOAs on the NCS typically include similar terms as the JOAs, with the addition of unit-specific regulations, for example relating to redetermination of the tract participation of each affected license group. General terms are standardized while more commercially oriented terms like tract participation, redetermination and handing of pre-unit costs are negotiated among the unit participants. The agreed terms and any subsequent amendments are subject to MPE approval.

Alternatives to a full UOA are the Right to Produce Agreements and Simplified Unit/Coordination Agreements, to be considered if the share of the deposit in one license area is limited or the ownership is the same in both/all relevant production licenses.

The PDO

The development of petroleum deposits is subject to the MPE's approval of a plan for development and operation (PDO). Furthermore, if the expected investments exceed certain thresholds, currently NOK 15 billion, the Norwegian Parliament must also approve the PDO.

The PDO includes a technical plan for the development project, a calculation of expected costs, and an impact assessment. Submission of the PDO rests with the MC and is adopted by a majority vote. After approval by the MC, all licensees are required to notify the MPE within a 3-month deadline whether or not they will accede to the PDO. If one or several licensees do not accede to the PDO, the acceding parties may carry out the PDO as a sole risk development project. Hence, the non-acceding licensee will still be a licensee but not participate in the relevant project.

Third-party access to existing production facilities and oil pipelines

Limited petroleum deposits in the proximity of existing infrastructure are often tied into existing nearby infrastructure for processing and other services. Therefore, existing production facilities and different types of infrastructure, such as oil pipelines, are subject to statutory principles on negotiated third party access. The general principles and procedures that apply are set out in separate regulations (the TPA Regulation).

Third-party access shall be granted on objective and non-discriminatory terms and conditions, provided that such access does not constitute an unreasonable detriment of the licensee's requirements or the requirements of a third party that has previously been granted a right of use.

Tariffs for third-party use shall be calculated based on an incremental principle and ensure that the profits from petroleum production are earned by the owners of the producing field and not by the owners of the host facility. Tariffs shall cover marginal costs and losses caused by the third-party use and a reasonable profit, considering the risks associated with the third-party use. Terms and conditions for third party access shall be based on standardized contract clauses approved by the MPE and published by the NPD. If the negotiating licenses cannot agree on tariffs or other terms, such disagreement may be referred to the MPE for a decision. In recent years, many negotiations have been referred, and the MPE has clarified the requirements to the terms to be offered by the host license in several individual decisions.

Third-party access to existing upstream gas infrastructure

The majority of the upstream gas pipeline network and processing facilities on the NCS is owned by an unincorporated joint venture, Gassled.

The upstream gas transport infrastructure on the NCS is subject to regulated third-party access. An independent system operator operates it, Gassco. Gassco grants access to users on objective and non-discriminatory terms to users with a duly substantiated reasonable need for transportation and/or processing capacity. Long-term and short-term capacity is offered, and capacity can be reserved in regular booking rounds.

The MPE determines the tariffs for regulated access to gas infrastructure and is set out in a separate regulation (the Tariff Regulation). The tariff consists of a capital element and an operating element. The capital element promotes resource management and gives the owners a reasonable investment return. The operating element is set to cover all operating costs of the system. The tariff relates to reserved capacity and must be paid irrespective of use (capacity fee). Unused capacity may be sold in the secondary market.

Transportation and processing services are governed by general terms and conditions determined by Gassco in consultation with owners and users and are approved by the MPE. The users (shippers) are liable for removal and abandonment costs for relevant infrastructure as per applicable terms and conditions. This liability is allocated between the shippers according to their share of cumulative capacity reservations in the various parts of the system.

Lifting and sales of petroleum

Each licensee has an individual right and obligation to take and dispose of produced petroleum in proportion to its license interest. Rules on the lifting of oil and gas are set out in the JOA, often supplemented by more detailed provisions in separate gas lifting and balancing agreements.

The MPE approves field-specific production schedules on an annual basis. By the end of each quarter, the MPE shall be provided with information about the quantities that have been sold during the quarter, to whom they have been sold, and the prices obtained. In addition, with similar frequency, the MPE shall be informed of obligations to deliver rich and dry gas from the NCS, including an overall profile of the contracted volumes and a description of the main conditions of the delivery contracts that have been entered into in the previous quarter.

Cessation of production and decommissioning

According to the Petroleum Act, licensees are required to submit a decommissioning plan to the MPE between two and five years before a relevant production license expires or is expected to be relinquished, or before the use of a petroleum installation will be discontinued permanently.

A decommissioning plan consists of two parts: an impact assessment and plans for disposing of the installations. The impact assessment shall provide an overview of the shutdown process's possible environmental and other impacts. The disposal part of the plan shall contain detailed plans for closing down operations and decommissioning installations in the best possible way.

The MPE decides how installations shall be disposed of and set a time limit for implementing the decision. The MPE may also stipulate additional and more specific conditions. For example, on a case-by-case basis, the MPE may opt for complete or partial removal of the relevant facilities, further use of the facilities as host infrastructure for other license groups or for other non-petroleum specific uses, or abandonment of the facilities without removal.

The licensees are liable for carrying out and paying for all decommissioning obligations stipulated by the MPE. Under the standard JOA, the parties are primarily liable for such costs on a pro-rata basis according to their respective participating interest, but secondarily jointly and severally liable. Thus, if one or more participants cannot pick up their share of the costs, the other participants will have to cover these costs proportionally, subject to any secondary liability for previous owners, as further discussed below. Decommissioning costs are tax-deductible.

Registration and mortgaging

The NPD keeps a register of all production licenses awarded on the NCS (the Petroleum Register). Subsequent transfers and any mortgaging of licenses are also registered. Mortgaging of a full production license, or an individual licensees' share of such, as part of the financing of activities associated with the license, is subject to approval by the MPE.

The MPE may also allow a mortgage of a license to secure activities relevant for other licenses of the mortgager on the NCS. In practice, the MPE normally consents to general mortgage arrangements comprising all licenses held by a licensee as part of financing such licensee's activities on the NCS. However, a production license cannot be mortgaged as part of financing activities other than petroleum activities on the NCS.

A mortgage of a license comprises all, or, in case of mortgaging of an individual licensee's share, a pro-rata share of rights that at any time follow from the license, as well as the mortgagor's other rights in connection with the activities carried out under the license.

A mortgage over a production license gains legal protection through the Petroleum Register registration.

In the event of an assignment of participating interests, such assignment shall be registered in the Petroleum Register by submitting the Bill of Sale with attachments. Such documents are typically tabled and reviewed in completing a transaction and subsequently submitted to the Petroleum Register. To avoid delays in the process and unexpected rejection of the registration, our advice is to initiate a dialogue with the Petroleum Register prior to completion of the transaction and have the documents pre-submitted and approved for registration.

Thommessen has a close relationship with the Petroleum Register and may facilitate this process.

Taxation

The key features of the current petroleum taxation system can be summarized as follows:

• The marginal tax rate on upstream petroleum activities on the Norwegian continental shelf is 78%, including a corporate tax base with a tax rate of 22% and a special tax base with a tax rate of 56%.
• Companies subject to the petroleum taxation system are entitled to linear tax depreciation of upstream investments over a period of 6 years with a tax value of 78%. In addition, such investments trigger additional tax deductions ("uplift") in the special tax base.
• Tax losses are carried forward with an interest compensation in order to maintain their value.
• The tax value of exploration costs are refunded annually, and the tax value of tax losses carried forward are refunded when E&P activities cease.

In 2020, temporary petroleum tax provisions were introduced to mitigate the effects of COVID-19. The temporary provisions provided immediate tax deductions for upstream investments and an increased uplift in the special tax base. These temporary provisions apply to all investments made in 2020 and 2021 and certain investments in subsequent years related to projects where a plan for development and operation (PDO), a plan for installation and operation (PIO) or certain other plans for approval are filed before 1 January 2023 and approved by the MPE before 1 January 2024.

On 31 August 2021, the Norwegian government announced that it would propose certain amendments to the Norwegian petroleum taxation system, introducing a cash-based tax system. On 3 September 2021, the Norwegian Ministry of Finance circulated a consultation paper setting out the proposed changes in more detail. The political situation has changed since this proposal was prepared, and it has resulted in a new Norwegian Government from the election for Parliament in September 2021. It is however expected that the petroleum tax system will be amended in the direction proposed by the previous Government as such seems to have broad support in the Parliament.

The main elements of the proposal can be summarized as follows:

• The marginal total tax rate of 78% on upstream petroleum activities on the NCS will remain unchanged.
• The corporate tax paid will be a deductible expense in the special tax base. The marginal tax rate of 78% will be maintained by increasing the special tax rate to 71.8%.
• Upstream investments will be fully deductible in the special tax base in the year they have incurred and will be subject to ordinary tax depreciations in the corporate tax base.
• The current uplift provisions will be abolished.
• Tax losses carried forward in the special tax base will be refunded annually. Tax losses carried forward in the corporate tax base will not be refunded, and will be carried forward without interest compensation.
• The current regimes of exploration refund, cessation refund and interests on tax losses carried forward will be abolished.
• The tax value of all tax losses and unused uplift carried forward as of 31 December 2021 will be refunded by the Norwegian State to implement the new tax system.

The proposed changes will not apply to investments comprised by the temporary provisions introduced in 2020. This means, assuming that the proposal will be adopted in the first half of 2022 and that changes will apply to investments made as of the tax year 2022, that during a transitional period from 2022, three different sets of rules will be applied in parallel; (i) investments made in the period 2016 – 2019 will be subject to tax depreciation under the existing tax regime (until and including 2024), (ii) certain qualifying investments from 2020 onwards will be comprised by the temporary provisions introduced in 2020 and (iii) investments made after 2022 (and not comprised by the temporary provisions) will be comprised by the new tax regime.