The state's ownership of offshore petroleum resources and its exclusive and sovereign rights to exploration for and exploitation of such resources were established by law in 1963. Excluding the Svalbard special regime, state ownership of onshore petroleum resources was established by law in 1973. There is no petroleum activity ongoing pursuant to the 1973 onshore resources legislation. No specific secondary legislation has been adopted for the purpose of petroleum activities governed by the 1973 legislation. All comments and descriptions included relate to offshore petroleum resources and related petroleum activities only.
For commercial entities to conduct upstream operations, government authorisation is required. A production licence (concession) is required for entities wishing to hold exclusive exploration (including drilling of wells) and production rights. Production licensees become owners of petroleum at the extraction point, but may only take their proportionate entitlement to petroleum at the production point, which is the point where petroleum may be transported in bulk as a commodity. An exclusive facilities licence (concession) is required to operate upstream facilities not included in an approved production project development plan.
Facilities may not be operated or used without a petroleum licence. Entities may own facilities used for petroleum activities, however, without itself holding a petroleum licence provided the operator of the facility holds the required petroleum licence (concession).
A specific facilities licence (separate from a production licence) does not grant licensee rights to petroleum exploration or production, only to construct and operate facilities.
An exploration licence (concession) is required to conduct non-exclusive collection of geoscience data for upstream operation purposes. An exploration licence only grants the right to collect data and does not confer any other rights or preferences to petroleum, or a production licence. The exploration licence does not include the right to drill any well, which is intended to penetrate petroleum-bearing strata. It only grants a licensee the right to drill a shallow well for calibration purposes.
Direct state participation is exercised through the State Direct Financial Interest (SDFI), as determined by the government on a discretionary basis. The SDFI participation in a petroleum licence is considered and subject to the petroleum regulatory and concessionary regime as a licensee, save for that pursuant to law the SFI is prevented from obtaining information relevant to selection of suppliers of goods and services and partaking in related procurement decisions. SDFI is not a legal entity separate from the state, but the SDFI petroleum licence interest and associated petroleum activities is not managed by an organ of the state, but managed by Petoro AS on behalf of the state. Petoro AS is a joint-stock company wholly owned by the state. Petoro is a portfolio manager conducting its business subject to Chapter 11 of the 1996 Petroleum Act (as amended) and with shareholder and corporate decision-making according to Norwegian corporate law, in particular the 1997 Private Limited Liability Companies Act. The Norwegian state also holds approximately two thirds of the shares in Statoil ASA, a publicly listed company. Only Statoil may be appointed operator of a petroleum licence, not Petoro. Gassco AS, another company wholly owned by the Norwegian state is appointed as system operator of the large submarine natural gas gathering and landing pipeline system having its landfall and onshore receiving terminals located in a number of continental European counties, as well as in the UK.
All regulatory functions are fulfilled by state institutions. No regional or local authorities have any specific regulatory authority over petroleum resources or upstream operations. Pursuant to applicable law and delegated powers, regional and municipal authorities have regulatory functions of a general nature that may also affect commercial petroleum activities, ie, where a development includes onshore facilities may require authorisations for planned use and management of land (including internal waters and harbours).
Stortinget (the national assembly) has ultimate legislative and budgetary authority pursuant to the constitution of 1814. Stortinget passes laws as well as the state budget, and grants Government authority to ratify all major international legal instruments. Any expense incurred in relation to petroleum resources, facilities or upstream activities not covered by applicable law or budgetary approvals must be submitted to Stortinget for approval.
The Government forms a cabinet comprising 20 ministers. The cabinet makes formal regulatory and budgetary decisions in meetings ceremonially headed by the King. The King in Council also adopts secondary legislation referred to as Royal Decrees.
Ministries are headed by cabinet ministers. One ministry may have more than one cabinet minister and may be in charge of more than one sector or activity. Each minister is in charge of the day-to-day activities within his or her area of responsibility. A ministry may, as in the case with the upstream petroleum sector, make administrative decisions applicable to individual cases and pass secondary legislation generally applicable to the sector in the form of ministerial regulations subject to applicable laws.
The Ministry of Petroleum and Energy (MPE) is the core upstream operations ministry in charge of petroleum resource management, upstream facilities and operations subject to Norwegian law and jurisdiction. This includes resources, facilities and operations on the Norwegian Continental Shelf (NCS) and the Norwegian mainland. It also includes activities outside the NCS when consistent with public international law, such as in relation to the gas and liquids trunk export pipelines to the UK and the European continent. The MPE is also in charge of activities conducted on transboundary fields subject to bilateral treaties. It manages the state's participation in SDFI, the SDFI upstream interest management company Petoro AS, the gas pipeline-system operator Gassco AS and the state's interest as shareholder in Statoil ASA. The MPE is also in charge of the Petroleum Insurance Fund and is the appeal body for appeals against decisions taken by the Norm Price Board. There is no upstream petroleum activities undertaken subject to the 1973 Land Petroleum Act (LPA).
The Norwegian Petroleum Directorate (NPD) reports to the MPE. Its primary task is to contribute to optimal, efficient and responsible resource management. The NPD is the technical advisor to the MPE and conducts NCS-relevant petroleum sector analysis and data management. In co-operation with other authorities, the NPD ensures comprehensive follow-up of petroleum operations and, subject to delegated power, develops secondary regulatory instruments and non-binding guidelines for upstream operations. The NPD is the registrar of the Petroleum Registry, in which exclusive petroleum rights must be registered as well as any MPE-approved mortgage or other security on facilities used in petroleum operations, subject to Norwegian law.
The Ministry of Finance is in charge of personal, corporate and petroleum special taxation, VAT and other indirect taxes, customs and excise. A special tax authority, the Oil Taxation Office, deals with corporate and petroleum special tax matters relevant to those companies that hold exclusive petroleum rights and participate in Norwegian upstream operations.
The Ministry of Labour and Social Affairs (ASD) is in charge of working environment and petroleum operations safety. The ASD's regulatory role comprises safety supervision, emergency preparedness (on facilities) and the working environment in both off- and onshore Norwegian upstream operations.
The Petroleum Safety Authority (PSA) is a directorate reporting to the ASD. The PSA has been delegated authority to monitor the core health, safety and working environment aspects of the upstream sector. Pursuant to law and delegation by the ASD, it is authorised to issue regulations covering safety and working environment for the upstream industry. It may take administrative decisions in the form of consents, make orders (prohibitions and exemptions) and issue fines. The PSA may temporarily suspend or shut down upstream operations. Its supervisory responsibility comprises oil and gas activities on the NCS as well as at production and processing facilities on land and their associated pipeline systems.
The Ministry of Transport and Communications (MTC) is in charge of the government's preparations for emergencies involving acute pollution from petroleum operations and shipping. Its advisory and executive body is the National Coastal Administration (NCA). The NCA is organised into five coastal regions. Its Department of Emergency Response is the specific department responsible for governmental preparedness against acute pollution.
The Norwegian Maritime Authority (NMA) is the administrative and supervisory authority in matters related to health and safety, material security and the environment on vessels flying the Norwegian flag and foreign ships in Norwegian waters. The NMA is also responsible for ensuring the legal protection of Norwegian-registered ships and registered rights in those ships. The NMA is subordinate to the Ministry of Trade, Industry and Fisheries and the Ministry of Climate and Environment. The NMA's activities are governed by national and international legislation, agreements and political decisions.
Petoro AS (Petoro) is a wholly state-owned company, which manages the State Direct Financial Interest (SDFI) in petroleum licences. Petoro itself does not apply for petroleum licences, as direct state participation in production licences is decided by government on a discretionary basis. The SDFI is considered a licensee, but the SDFI licence interest is managed by Petoro on behalf of the state. Petoro is not in charge of selling SDFI petroleum production entitlements, which is done by Statoil on behalf of the state, and only supervised by Petoro.
Petoro AS was established pursuant to Chapter 11 of the Petroleum Act and legislation applicable to limited liability companies. Petoro's corporate governance, documents and decisions are subject to the 1997 Limited Liability Companies Act. Beyond what follows from ordinary limited liability company corporate law requirements, Petoro has to submit certain long-term and other qualified plans for the general assembly's approval. Petoro votes in the unincorporated joint venture established pursuant to the petroleum licence with, in principle, the same powers as any other licensee, but it does hold certain veto rights in the joint venture for the protection of the state's resource management interests. Petoro is, however, excluded from participating in public procurement decisions, consistent with applicable law based on EEA public procurement obligations.
Gassco AS (Gassco) is a wholly state-owned joint-stock company dedicated to functioning as the system operator of Gassled - the submarine gathering, transportation and landing pipeline system for natural gas extracted from NCS resources. Gassco cannot own any pipelines, terminals or gas extracted or produced. Gassled IS (Gassled) is the owner of Gassled and holds a facilities licence. Gassled is organised as an unincorporated joint venture in the same fashion as the NCS production licence. Gassled jointly owns almost all upstream gas transportation pipelines and their related onshore terminals.
Equinor ASA (previously Statoil ASA)
Statoil ASA (Statoil) changed its name to Equinor ASA in 2018. No corporate changes was made and the company remains a publicly listed joint stock company in which the state holds 67% of the shares. Previously, when the company then named Statoil was wholly owned by the state, the company was allocated participation interests without application, according to government decisions. Currently, however, it is awarded rights like any other applicant and is subject to the same regulatory requirements as other licensees. Equinor still sells the SDFI oil and gas production entitlements on behalf of the state. Previously it also sold royalty volumes on the state's behalf, but this has been discontinued as royalty on all petroleum production has been terminated. (
The Norwegian upstream petroleum regime may be divided into three segments, based on the location of the resource in question.
All current exploration and production of petroleum from offshore resources is subject to the Act of 29 November 1996, No 72 (the Petroleum Act or PA) together with sundry secondary legislation passed by the King in Council, the Ministry of Petroleum and several directorates. The PA is supplemented by a number of regulations, predominantly adopted as Royal Decrees, Ministerial or Directorate Regulations. The King in Council, the MPE and the NPD also make individual decisions of a regulatory nature based on delegated power under public administrative law. Non-binding guidelines are also published.
The title to all petroleum resources in the ground, whether on the NCS or mainland territory, is vested in the state. The PA regulates resources located in the seabed of the NCS, facilities and petroleum operations (exploration and production, including transportation) and related activities associated with these resources when subject to Norwegian jurisdiction and petroleum rights licences granted to licensees are awarded as public administrative law concessions, not negotiated as private law contracts. The PA also covers exploitation of these resources when exploitation takes place outside of Norwegian law jurisdiction or in association with production (as defined by the PA). Upstream facilities, petroleum (operations) activities conducted onshore in Norway and outside the NCS may be governed by the PA when Norway exercises jurisdiction consistent with its international law obligations.
In accordance with Sections 1-5 of the PA, other Norwegian laws also apply to petroleum operations and facilities subject to the PA. It is worth noting that the PA operates within a wider scope of activities, referred to as "petroleum activities", which are more extensive than the common industry understanding of "petroleum operations". This is particularly relevant when planning, preparation and management of NCS operations is undertaken by staff located outside of Norway.
Other important Acts with substantial impact on petroleum activities are:
The core purpose of the Norwegian petroleum regime applicable to offshore resources is expressed in sections 1-2 of the PA, in particular the second paragraph stating that: "Resource management of petroleum resources shall be carried out in a long-term perspective for the benefit of the Norwegian society as a whole. In this regard the resource management shall provide revenues to the country and shall contribute to ensuring welfare, employment and an improved environment, as well as to the strengthening of Norwegian trade and industry and industrial development, and at the same time take due regard to regional and local policy considerations and other activities."
The PA has remained in place, with moderate amendments, since it entered into force on 1 July 1997. The most significant amendments that have been made to it came in 2003 following the part privatisation of Statoil and the formation of Petoro AS and Gassco AS, including the establishment of rules applicable to third-party access to the upstream gas pipeline system operated by Gassco (the "tariff regulations"). Gassco now manages capacity bookings and capacity allocation, and the MPE has issued regulations stipulating conditions for access and tariffs to be paid to Gassled. All shippers with a duly substantiated need for capacity shall have access to Gassled on a non-discriminatory, objective and transparent basis. Tariffs are based on booked capacity, not throughput.
There are also a number of subsequent Ministerial and Directorate Regulations adopted pursuant to the PA or in combination with other Norwegian Acts (see below).
The PA and the PR form the legal basis for the licensing regime organising licensing rounds for frontier acreage and annually for previously licensed acreage.
In 2005 a separate regulation for third-party access and use of facilities for extraction, production and transportation was passed (Ministerial Regulation of 20 December 2005, No 1625), regulating the procedures and requirements for access to and use of facilities other than those regulated by the tariff regulations related to the Gassled facilities.
There are several additional regulations adopted by the MPE, NPD and the PSA on resource management, operations, facilities, HSE and fiscal metering governing upstream petroleum activities pursuant to a petroleum licence (concession). The main regulations enforced by the NPD and the PSA are adopted by Royal Decree, Ministerial or Directorate Regulations pursuant to the Petroleum Act, the Working Environment Act, the Fire Protection Act, the Product Control Act and the Electric Installations Act and several Acts pertaining to healthcare and healthcare personnel. In addition to the Petroleum Regulations, the main regulations are to be found at www.npd.no and www.ptil.no.
There are also a number of labour law regulations adopted by the ASD and Labour Inspection Authority relating to the workplace, including acceptable threshold values and limits for exposure in the working environment, performance of work, organisation, management and employee participation, labour hire undertakings, and worker identification requirements, etc. In addition to www.ptil.no, www.arbeidstilsynet.no may also be consulted.
The Act of 4 May 1973, No 21 (the Land Petroleum Act or LPA) governs upstream petroleum operations and facilities for the purpose of exploration for and production of petroleum resources in the subsoil of Norwegian land territory, as well as the narrow band of seabed close to shore that may be subject to private property rights. No detailed regulations have been adopted to implement the LPA to date. No exclusive upstream rights or petroleum (operations) activities based on onshore resources have yet been conducted due to the geological structure (mostly base rock) on most of mainland Norway.
The PA and LPA do not apply to Svalbard. Svalbard's territory is subject to Norwegian sovereignty pursuant to the Svalbard treaty. The Svalbard regime follows a separate Mining Code applicable only to activities in the Svalbard territory.
Exclusive exploration and production rights, as well as rights to construct and operate facilities related to offshore petroleum deposits, are only available subject to a public administrative law-based concession. These take the form of either a production licence (concession) or a facilities licence. The exclusive exploration and production licence has been in place since the first licensing round awards in 1965. No onshore licences have yet been awarded, but if rights were to be awarded then they would also be public administrative law-based concessions.
All exclusive petroleum licences are normally required to have more than one participant. In the case of a production licence, the participants will be compelled, as a condition of the award, to enter into unincorporated joint venture and be subject to a model petroleum agreement containing two mandatory exhibits: the joint operating agreement and the accounting agreement.
From 1965 until 2007, the format of the petroleum agreement changed stepwise. After this date, the system was harmonised to be identical to all operative production licences. For facilities licences, the type of joint venture that must be established may have different formats. However, since the formation of Gassled, most of the joint ventures related to gas pipelines that operated under a facilities licence are now established as unincorporated joint ventures under a standard agreement approved by the MPE.
Consistent with EU internal market rules, as stipulated by the so-called Licensing Directive and implemented in Norwegian petroleum law, legal and physical persons from EEA member states may apply for an exclusive production licence or the transfer of a production licence's participation interest. In practice, the MPE has not distinguished between EEA entities and non-EEA entities due to the ease of establishing an EEA entity and thereby effectively bypassing potential discrimination between EEA and non-EEA entities by simply incorporating an EEA entity. However, it is difficult to envisage that a single physical person may fulfil the technical, capacity, organisational and financial requirements of the law to obtain a Norwegian offshore production licence participating interest.
Persons or entities subject to international embargo by the UN or the EU will not be permitted to obtain participation interest in a production licence or take over an entity holding such exclusive rights. Investors may be privately or publicly owned or controlled.
The relationship between the state and commercial entities that have been awarded upstream petroleum rights is governed entirely by Norwegian public administrative law. The rights of such entities are public administrative law-based concessions, not private law-based licences. They are not founded on the basis of the state having title to petroleum resources, but on the basis that the state, consistent with public international law, exercises exclusive sovereignty over its territory and sovereign right over the NCS and any exploration for or exploitation of its natural resources.
The PA and PR alone establish the domestic law basis for awarding non-exclusive and exclusive upstream petroleum licences. Some of the obligatory documents executed pursuant to a production or facilities licence (the JOA and the ACC) may have dual functionality in as much as they are conditions of the granting of an award, but at the same time form an agreement between licensees (see below).
Before any petroleum operations (under the PA, as mentioned in 1.4 Principal petroleum laws and regulations, "petroleum activities" is given a specific definition and slightly more comprehensive meaning than the conventional industry term "petroleum operations") by commercial entities are permitted, the area must be opened for petroleum activities. Only the Norwegian government may conduct petroleum activities without being issued a concession, licence or permit, but such activities must be conducted in accordance with the applicable procedural and material rules of the upstream petroleum regime.
To open new areas for petroleum activities the government prepares a comprehensive (strategic) environmental impact assessment (SEA). The SEA, as well as other important information (the petroleum potential of the area, the impact on the petroleum industry, related businesses, the non-oil economy, infrastructure and local communities, etc.), are collected, analysed and submitted in a report to Stortinget in a "Stortingsmelding" ("St meld" or White Paper) including a recommendation with regard to opening new area(s) for petroleum activities. The report is then subject to parliamentary debate.
A "Stortingsmelding" is a report to Stortinget by the government on the policies it intends to implement, but is not formally adopted. Under the Norwegian constitutional parliamentary system, however, the government is compelled to take notice of the parliamentary majority. It may also have to return to Stortinget to implement its policies because they require legislative or budgetary decisions.
Following an affirmative vote, the MPE allows the NPD to award non-exclusive exploration licences and the MPE prepares, announces and obtains cabinet approval for the awarding of exclusive production licences. All applications for licences require the payment of a nominal administration fee.
Prior to announcing the licensing rounds, pre-qualified industry players are invited on a voluntary and confidential basis, to nominate acreage they would wish to see included in the forthcoming bid round. Only prequalified entities may submit an application for a production licence. Prequalification follows a defined process in which the regulatory authorities look into the applicant's operational and financial capacity, capability, experience and previous conduct.
Generally, a production licence is awarded to a group of applicants compelled to form an unincorporated joint venture. Individual and group applications are permitted. However, the MPE is not bound to award the licence according to such group applications and may exclude any group applicant or include other applicants in the licence award. Awards are based on open and non-discriminatory terms and conditions consistent with EU internal market rules implemented in Norway as part of the European Economic Area (EEA) obligations.
No production licences are negotiated individually, but are awarded pursuant to public bidding rounds. Awards are made based principally on an applicant's geoscientific understanding of the area applied for, its operational and financial capacity, experience and plans for the area. Each licence is awarded on a standard formula production licence document to which is annexed a Petroleum Agreement establishing the obligatory unincorporated joint venture under which licensees are joint and severally liable. Annexed to the Petroleum Agreement are exhibit A, a standard joint operating agreement, and exhibit B, a standard accounting agreement. Exhibits A and B are non-negotiable. The licensees must enter into the Petroleum Agreement as a condition of the award of a production licence, and for the licence to remain in force.
Variations between production licences are normally limited to the licence acreage, the licensees and their respective participation interests in the licence, the voting rules, the appointed operator (which is one of the licensees), the obligatory work programme and any individual limitations on activities of a geographical or seasonal character.
Non-exclusive exploration licences are awarded according to an "open door" policy. The NPD awards exploration licences pursuant to delegated authority under the PA and PR. The licence is time limited to three years and enables independent seismic companies as well other interested parties to collect seismic data and other exploration-related activities, including drilling a shallow well for calibration purposes if required.
The procedure for being awarded an exploration licence and the material requirements necessary are regulated by the PA and PR. A single entity may be awarded an exploration licence. Additional regulatory and reporting requirements must be fulfilled before and during seismic acquisition or offshore activities. Having been awarded a non-exclusive exploration licence does not give the licensee any privilege, preference or right of any nature to obtain an exclusive production licence. There is no state participation in exploration licences.
Frontier acreage licensing rounds currently occur on a bi- or tri-annual basis. The annual licensing rounds referred to as "Awards in Predefined Areas" (APA) consist of acreage previously licensed and relinquished or in proximity to existing upstream production facilities. The difference between the two types of production licences is principally the duration of the initial exploration period and the content of the obligatory work commitment or programme.
In ordinary licensing rounds, it is not common to include more than a data collection and analysis, as well as one or more obligatory or contingent exploration wells, as obligatory work commitments. In APA licences, it is quite common that licensees plan at the time of the production licence award, will have to commit to all relevant activities required to submit a development plan. A system of "execute or drop" is usually included in the work programme, obliging the licensees at certain decision gates to decide whether to enter into a new activity phase (and extended licence period) or to surrender the licence. The extension into a development and production period of up to 30 years, and in exceptional cases up to 50 years, is conditional on the fulfilment of the prescribed work commitment. For APA licences, such extensions regularly require licensees to prepare and submit a development plan.
Facilities licences are not awarded based on bid rounds like production licences, but rather awarded as a result of the government approval of an application to construct and operate facilities. Licensees to a facilities licence normally form an unincorporated joint venture. These facility licences typically comprise installations or pipelines serving several production projects under different production licences. Previously such dedicated facilities licences were obtained almost exclusively by entities that at the same time have a direct interest in the use of the facilities in question, for use in connection with one of more production projects in which these licensees have a participating interest. This pattern has over the years somewhat changed in particular in relation to petroleum licences held in submarine pipelines absorbed into the Gassled natural gas gathering and landing submarine network.
State participation is no longer mandatory, but discretionary. Lately, it has only been imposed on a limited number of production licences. When state participation is imposed, the participating interest is held by SDFI and managed by Petoro.
All entities engaged in petroleum activities related to NCS resources are subject to Norwegian personal and corporate income and capital gains tax. Entities with their principal place of business outside of Norwegian tax jurisdiction may be entitled to tax relief, exemption or credit in their home jurisdiction. Entities holding an exclusive petroleum production licence are also subject to the special petroleum tax.
For fiscal purposes, a norm price system is stipulated on crude oil-related transactions that are not conducted in an open, arms-length and transparent market.
No economic terms are negotiated in Norwegian petroleum licences. State participation may be proposed in an application, but whether or not the state actually participates remains a decision at government's discretion at the time of the licence award. There are no local content quotas related to material, goods, services or employment of personnel. No production bonuses are currently imposed, no production or profit splits are authorised and there are no longer any royalty obligations.
Production bonuses may be imposed pursuant to law, but this provision has never been used. For production projects with a development plan approved before 1 January 1986, royalty was imposed separately on crude oil (liquids at atmospheric conditions) and natural gas (gaseous components as atmospheric conditions), but such obligations have been discontinued.
There are no longer societal obligations in kind or in cash. Previous systems of this nature were discontinued many years ago. Licensees have to offer the government the possibility to allow civil servants and petroleum sector teachers to participate in licensee training programmes. Participation in these programmes is diminishing in terms of both number of participants and frequency.
An administrative fee for services rendered has to be paid for all licence applications. These fees are related to the cost the public administration incurs for assessing applications and awarding the licence. There are also fees to be paid in relation to regulatory authorities' monitoring and control of petroleum (operations) activities. These fees are also service fees and have no fiscal nature or effect.
For production licences, an annual progressive acreage fee applies for all acreage held beyond the period initially allocated to perform the obligatory work commitment. This does not apply to acreage covered by an approved development plan. There is no acreage fee for any other petroleum licences.
In special circumstances, the PA allows the state to impose a fee for approval of transfer of licence rights or rights associated with upstream facilities. This fee may entail payment beyond for costs associated with services provided. No such fee has been imposed to date.
Under the General Tax Act (GTA), a company that is resident in Norway for tax purposes is subject to income tax on its worldwide income, including income derived from upstream petroleum (operations) activities subject to Norwegian jurisdiction. However, non-resident companies are not subject to tax pursuant to the GTA for petroleum (operations) activities on the NCS. The Petroleum Tax Act (PTA) extends the geographical scope of the GTA to include income generated by these companies when related to petroleum activities on the NCS. The GTA corporate income tax rate is 22%.
The PTA contains special rules relating to taxation of petroleum activities with regard to cost allocations, deductions, depreciations, etc. The PTA also introduces the statutory basis for taxation of the resource rent associated with the production of petroleum (petroleum special tax). The petroleum special tax rate is 56% in addition to the 22% ordinary income tax rate under the GTA. The marginal tax rate on entities holding exclusive petroleum rights is 78%.
The PTA applies to extraction, processing and pipeline transportation and, additionally, to certain ancillary activities. Only extraction, processing and pipeline transportation give rise to the petroleum special tax, except in cases where the tax authorities, pursuant to delegated powers may determine that an onshore plant connect to production of petroleum shall be included, such as in the case of the Snøhvit, Melkøya plant. The ancillary activities are thus only subject to ordinary corporate income tax at a rate of 22%. The assessment of whether a particular activity triggers the special petroleum tax (typically an activity in support of, or ancillary to, production or transportation) may be difficult.
Petroleum operations costs, including exploration costs, are tax deductible when incurred. A system was implemented in 2005 whereby a licensee may claim a cash refund from the state of the tax value of direct and indirect NCS-related explorations costs (financial costs excluded). This cash refund may only be claimed to the extent that the amount in question does not exceed the annual loss in ordinary income and in the basis for special tax, respectively.
At its sole discretion, the state may take a direct participatory interest in an exclusive petroleum licence by reserving a participation interest for the State Direct Financial Interest (SDFI). The state participation interest held by SDFI and managed (almost without exception) by Petoro AS. SDFI participation is no longer "carried" during the exploration phase. The previous "carried state interest" (Statoil- and SDFI held licence participating interest) required the commercial participants in a production licence to pay initially, but subsequently after approval of a development plan, have refunded the costs associated with exploration. SDFI contributes subject to cash-call issued by the Operator, its proportionate share of costs associated with petroleum activities in the respective petroleum licence from the day of licence award until completion of facilities decommissioning.
State-owned or controlled entities have no special privileges or rights with regard to the awarding of exclusive upstream licences. Neither Statoil ASA nor any of its subsidiaries any longer have privileges or preferences with regard to participation in exclusive upstream petroleum licences. Statoil competes with other applicants for any participation interest and for appointment as operator.
Norway is a member of the European Economic Area (EEA) and through this agreement part of the EU internal market. As a result, non-discriminatory rules, including the so-called four freedoms, apply to Norwegian upstream and downstream petroleum activities and entities applying to hold petroleum exclusive or other rights or conduct petroleum activities, including in particular downstream natural gas transmission, storage and distribution. The non-discriminatory obligation principle only legally applies to legal or physical persons resident in EEA jurisdictions. Unless special circumstances apply, such as UN- or EU-mandated sanctions, the non-discriminatory practice applies to all entities.
Norway is a member of the European Economic Area (EEA). The EEA internal market's non-discriminatory rules, including the so-called four freedoms, apply to Norwegian upstream petroleum activities, including procurement.
Local content provisions granting preferences to Norwegian owned or controlled suppliers, goods, services, personnel or capital originating from Norwegian sources contrary to the four freedoms and detrimental to entities, goods, services, personnel or capital provided from the EEA are not permitted under Norwegian applicable law. The PA requirement that supply bases may have to be located in Norway for the purpose of resource management, health, safety and emergency preparedness is not considered a local content requirement. Similarly, the PA requirement of licensee organisation in Norway is not a local content requirement, but is based on an individual assessment of the need for local organisation to fulfil the licensee's obligations related to resource management, HSE requirements, etc pursuant to law
The PR requirement to use principally the Norwegian language to the greatest extent possible is not a local content rule. This rule is imposed for the same reasons as the supply base provision. Furthermore, all applications for authorisations of any kind and all administrative decisions by authorities are made in Norwegian. Other languages may be used when necessary or reasonable, however, typically in contracts and communication with foreign suppliers.
Apart from the state, only holders of a production licence may develop and produce NCS sub-sea petroleum deposits. Licensees decide on whether or not to develop deposits that are discovered. Pursuant to PA Chapter 4 and PR Chapter 4, the licensees must submit a development plan for MPE approval. This plan shall consist of two parts: a technical and economic plan with detailed descriptions of production profile, offtake solutions for liquids and gas, infrastructure requirements, how facilities may be decommissioned, financing of the project, etc, as well as a progress plan. The development plan must contain a description of alternative development solutions and the licensee's preferred solution. This part of the plan will not enter the public domain.
The second part of the plan is a comprehensive area and activity specific environmental impact assessment as stipulated by statutory provisions. The assessment is based on a previously approved programme for data collection and assessment. The specific environmental impact assessment is publicly consulted with concerned stakeholders and the resultant report is a public domain document.
Staged or phased developments are permitted, provided all phases or stages are addressed in the development plan. Development and production from other deposits than those that are addressed by the plan will regularly require a new or amended plan, and any plan, when approved, only applies to the deposits included within it. The obligation to submit a development plan may be waived by the MPE under certain terms. This normally only applies to minor additions or amendments to an existing plan.
Unless MPE pre-approval is obtained, licensees may not commit to substantial contractual undertakings before the development plan has been approved. Licensees may apply to the MPE to waive this obligation, ie, for long-lead items, which is done subject to conditions including that the pre-approval may not be invoked as an argument for approval of licensees' preferred development solution.
Under special circumstances, a summary of the development plan and a request for the consent of Stortinget may be required. This is typically the case when the SDFI investment is above a threshold previously stipulated in the annual state budget, or for particularly important development policy or state revenue issues.
The MPE is not compelled to approve licensees' preferred development solution, but if the authorities are not happy with the proposed solution then the result is often consultation with licensees to amend the plan before it is submitted rather than outright rejection of it. A decision to approve or reject a development plan is an administrative law-based decision subject to appeal.
Any significant deviation from facts or alterations of terms and conditions on which a submitted or approved development plan is founded must immediately be communicated to the MPE.
Supply of petroleum to cover national requirements is regulated by the PA and is non-discriminatory. Supply compelled under these rules shall be paid for at rates consistent with market prices. Only crude oil and other liquids may theoretically be required, as Norway consumes practically no natural gas at all, and is not in need of natural gas for electricity or other energy supply purposes. All energy supply for purposes other than transportation is covered by hydroelectric power generation.
The emergency rules for supply in cases of national emergencies or war are included in the PA and are non-discriminatory. The rules are established in line with applicable exceptions to EEA internal market rules. None of these rules have been invoked to date. Given the Norwegian energy mix, it is unlikely that the state will have to rely on these provisions to secure domestic supply as long as there is substantial production on the NCS and the state holds a substantial participating interest in several production projects.
The outer time limits of both the exploration period and the development and production period are stipulated by law. The exploration period, which is calculated from the award of the production licence, cannot exceed ten years. The most commonly used initial exploration period is eight years for frontier areas and may be reduced for awards in predefined areas (APA).
In any production licence, the exploration period may be subdivided and always contains a number of obligatory work commitments depending on the maturity of the acreage and the available data. There are also statutory mandatory acreage relinquishment obligations that require such obligations to be stipulated in the production licence. In APA licences, all acreage regularly reverts to the state if the acreage does not cover a deposit included in a submitted development plan. In production licences, environmental or safety restrictions are often imposed, normally in relation to the marine environment or particularly severe weather conditions.
The development and production period is calculated from the end of the initial (exploration) period of 30 years, in exceptional cases up to 50 years, comprising development, including construction and commissioning of facilities, and production of the deposit(s) included within a development plan.
Beyond limitations following from international sanctions binding on Norway or domestic delivery obligations pursuant to law (under extraordinary circumstances), licensees are free to export all petroleum produced. Currently no liquids are reserved for the domestic market, but are instead delivered into the worldwide market or sold to affiliates of the licensees. The majority of the liquid volumes are loaded onto tankers offshore. Some volumes are landed onshore by submarine pipelines before being shipped. All natural gas that is not consumed for production purposes or reinjected is transported through large submarine trunk pipelines and sold almost entirely to the UK and the central European market. The exception is the Barents Sea Snøhvit gas production project, where the natural gas is shipped and delivered to the market as LNG.
According to PA Sections 10-12, no direct or indirect transfer of all or part of a participating interest or change of control over a licensee may take place without approval of the MPE. In addition, all such transfers must also be approved for tax purposes (explicit consent or through procedure for notification of compliance) by the Ministry of Finance (MFIN). Any such transfer will only be approved if the transferee is a legal or physical person qualified as a licensee. PR Section 72 is also relevant to this.
Transfer of a participating interest in a licence is also regulated by the petroleum agreement regulating the unincorporated joint venture formed by the licensees. Petoro, on behalf of the state, has a limited pre-emption right in exclusive petroleum licences. No transfer of production licence rights prior to completion of the mandatory work obligation are permitted without the consent of the other parties to the petroleum agreement. However, the transfer of control over a licensee (corporate transaction) holding a participating interest in a petroleum licence is not subject to that participant's approval. The protection of the other licensees in a production licence is thus safeguarded by the MPE assessment of such transfer pursuant to the PA Sections 10-12.
Transfers of non-exclusive exploration licences are normally not executed, as they are very time-limited and contain no obligatory work commitment or continuous activity beyond the activity specifically authorised.
A transfer of a production licence participating interest will only be permitted to a pre-qualified entity. The MPE assessment prior to approval is focused on the transferee's potential contribution to the licence in question and whether the transferee has the required organisational capacity, technical capabilities and financial strength sufficient to actively participate in petroleum (operations) activities going forward. Requirements for approval of a transfer will be dynamic and hence different for an early-phase exploration project compared to a complex development or production project. The NPD and PSA are consulted prior to approval of any transfer of interest or control. Participating interest and change of control transfer approvals may be conditional with regard to transfer of operatorship.
An application for transfer of operatorship may not form part of a transaction between licensees for participating interest or assets, but if a licence asset transaction or a corporate transaction is undertaken and involves the licensee as appointed operator, then such change is subject to separate MPE approval as described above. No tax assessment is required for operator transfers as the operator conducts day-to-day business on behalf of fellow licensees on a no-gain no-loss principle established by the petroleum agreement.
The MFIN assesses tax effects of the proposed license or corporate transfer. An automatic consent procedure for four standardised transaction models where the resultant tax effect is neutral through continuity has been established by regulation. Consent is obtained provided the parties confirm to the MFIN in writing that the transaction meets certain regulatory requirements. If they do not do this, then a formal Petroleum Special Tax Act Section 10 assessment will be undertaken. MFIN approvals may be conditional. Under the Act, the MFIN is delegated powers to deviate from ordinarily applicable tax laws if necessary in order to ensure tax neutrality.
Any change of participation interest in an exclusive petroleum licence or facility must be registered in the Petroleum Registry. Establishment or change in a mortgage, encumbrance or security in an exclusive petroleum licence or upstream facility must be approved by the MPE. In the case of default, providers of security will only be afforded limited step-in rights.
Petroleum production may in principle not be conducted expect for in accordance with an approved development plan and a production permit. The production premium is issued primarily subsequent to regulatory authorities having satisfied itself that the concessionaires are conducting their activities consistent with regulatory requirement, in line with previously submitted production profile and supporting information and in such a manner that petroleum or reservoir pressure is not wasted. The production permit system is primarily in place to ensure systematic pursuance of optimal resource depletion, as concessionaire communication to the authorities the reasons supported by documentation of why any deviation from the development plan and the associated forecast production profile is necessary or recommended. Over the 50 years of Norwegian petroleum production the production permit has been used to regulate the production level at individual production projects in a few isolated incidents of limited duration. That has in each case been justified for state economic reasons and implemented in such a fashion that individual licences among themselves, and in relation to the state, carried the economic impact proportionally.
The Norwegian upstream petroleum regime based on the 1996 Petroleum Act (would also likely have been applied to activities pursuant to the 1973 Land Petroleum Act (LPA) if any rights had been awarded or activities conducted) regulates all petroleum activities and facilities upstream of the defined delivery point for petroleum transported in bulk as a commodity.
Any petroleum activities or facilities located downstream of the delivery point and, provided such activities or facilities are subject to Norwegian law and jurisdiction, save for the downstream natural gas sector, is regulated by a variety of laws generally applicable to industrial sectors. Investment in downstream activities or infrastructure, except for natural gas transmission and distribution pipelines and natural gas storage, is guided by the same regulatory regime as any ordinary industrial activity that involve the construction, operation of use of infrastructure.
Investment in construction, operation and use of downstream natural gas transmission and distribution pipelines and storage facilities is subject to both the Act of 28 June 2002, No 61 on common rules for the internal market in natural gas (NGA), and the subsequent MPE regulations of 14 November 2003 (NGR). These rules are consistent with the EU third internal market in natural gas regulatory package, implemented in Norwegian law as part of Norway's EEA obligation.
NGA and NGR rules do not regulate the rights of either landowners or property right-holders. If access to property cannot be gained based on agreements with the landowner(s) or property right-holder(s), and for this reason has to be enforced, such enforcement must be executed through the ordinary statutory material and procedural rules applicable to expropriation. Such expropriation is subject to compensation. Both expropriation and compensation may be contested in front of the ordinary courts.
There are no state or private monopolies with regard to investment in upstream or downstream pipelines, landing terminals, plants or refineries. Only in upstream gas gathering and landing trunk pipelines is there a state-owned system operator (Gassco AS). According to applicable law, Gassco is not permitted to own any pipelines or terminals, or to conduct activities downstream.
EU internal market third-party access rules based on negotiated access as implemented in the NGA and the NGR apply (see 3.1, Forms of Allowed Private Investment in Midstream/Downstream, above).
There are no state or private monopolies with regard to investment in transmission or distribution pipelines or storage facilities. Access to natural gas networks is subject to negotiation with the system owner and operator. Access is subject to applicable law and is granted on non-discriminatory terms and conditions consistent with EU internal market requirements.
Pursuant to the Natural Gas Act (NGA), the Natural Gas Regulations (NGR) and by delegation from the MPE, a concession for the establishment of a natural gas pipeline network must be obtained from the Norwegian Water Resources and Energy Directorate. Land rights must be obtained from landowner(s) or property right(s)-holder(s), while construction permits and environmental permits must be obtained from other competent authorities, in some cases from regional or local authorities.
The delineation between Upstream and Downstream is outlined above (see 3.1, Forms of Allowed Private Investment in Midstream/Downstream). The Norwegian petroleum regime in principle follows the same legal and regulatory delineation. Downstream licences related to natural gas as well as downstream activities related to any other activities downstream of the commodities delivery point (see above) are subject to the ordinary Norwegian tax and fiscal regime. The upstream petroleum special tax regime does not apply. Tariffs are based on the norms implemented in Norwegian law consistent with the EU internal market rules applicable to downstream natural gas activities.
Downstream licences are subject to the ordinary Norwegian tax and fiscal regime. The General Tax Act (GTA) with a corporate income tax rate of 22% applies. The upstream petroleum special tax regime does not apply.
No such company or special rights exist in relation to downstream petroleum licences.
No local content requirements are applicable to downstream operations by private investors. See comments on jurisdictional delineation between Upstream, Midstream and Downstream above in 3.1, Forms of Allowed Private Investment in Midstream/Downstream.
The terms of downstream licences are determined by the NGA, the NGR and the MPE's subsequent delegation of power to the Directorate for Water Resources and Energy, dated 23 September 2009. Only one such concession has been granted to date.
Legislation contains mandatory obligations relating to the use and operation of natural gas pipeline systems with regard to third-party use, tariffs and information to the authorities, users, consumers and the general public. Dispensations or exemptions may be granted pursuant to the law. The concession may otherwise contain specific individual conditions necessary for the protection of public or private interests within the limits of public administrative discretionary power. These administrative powers are limited by public administrative law and principles for discretionary administrative authorities as outlined in the Public Administration Act and related regulations.
Concessions are grated to physical or legal persons subject to application consistent with regulatory terms, conditions and procedures. Concessions are granted for 30 years, but may be extended. Individual conditions may be stipulated with regard to system operational safety, gas supply quality, price and regularity, including security of supply, energy efficiency and for reasons associated with climate change.
There is no standardised concession or licence. Conditions to be implemented must be objective, transparent and non-discriminatory. Legislation is based on and consistent with Norwegian EEA obligations for the energy sector as formulated for the EU internal market in natural gas. Specific terms for application and award of a concession are outlined in Chapter 2 of the NGR.
See 3.1 Forms of Allowed Private Investment, above.
EU third-party access rules based on negotiated access as implemented in the NGA and the NGR apply. See 3.1 Forms of Allowed Private Investment, and 3.8 Other Key Terms of Each Type of Downstream Licence, above as applicable.
No such restrictions apply except for in the case of a declaration of a national emergency, in which emergency legislation enters into force.
EU internal market rules, including the four freedoms, the prohibition of quantitative (import and) export restrictions and competition law applies to petroleum marketing and sales. Beyond limitations following from international sanctions binding on Norway or domestic delivery obligations pursuant to law (under extraordinary circumstances), licensees are free to export all petroleum produced.
To establish or operate a downstream natural gas transmission, distribution or natural gas storage or regasification facility, a licence (concession) is required. Only qualified entities may hold a licence. Each licence may contain conditions. EU internal energy market principles requiring vertical unbundling apply. The same applies to LNG production facilities, to the extent such facilities are not comprised by an upstream production project (see 2.8 Other Key Terms of Each Type of Upstream Licence, above and 6.2 Liquefied Natural Gas (LNG) Projects, below). Other downstream petroleum facilities than those used for downstream natural gas purposes are not regulated by Norwegian petroleum dedicated legislation, but are subject to a host of Norwegian laws applicable to large industrial facilities handling hazardous products or processes.
Because of its EEA obligations, Norway has implemented the EU four freedoms of movement of goods, services, capital and persons. Competition law applies consistent with these obligations, including the right of establishment.
See comments under 1.2 System of Petroleum Ownership, and 1.4 Principal Petroleum Laws and Regulations, above.
Other important Acts, beside Chapters 7-9 of the PA (supported by the Petroleum Regulations and the Framework Regulations) that have a substantial impact on petroleum activities with regard to HSE are:
• The Act of 13 March 1981, No 6 relating to protection against pollution and to waste.
• The Act relating to working environment, working hours and employment protection, etc (the Working Environment Act). This Act has resulted in several regulations partly applicable to the upstream petroleum sector (see above on PSA-enforced regulations), including the Act of 14 June 2002, No 20 on prevention of fire and explosions from hazardous substances and emergency response by fire protection agencies. This act has resulted in several regulations partly applicable to the upstream petroleum sector (see above on PSA-enforced regulations).
• The Act of 24 May 1929, No 4 pertaining to supervision of electrical installations and equipment. This act has resulted in several regulations partly applicable to the upstream petroleum sector (see above on PSA-enforced regulations).
• The Act of 21 December 1990, No 72 relating to tax on discharge of CO2 in petroleum activities on the continental shelf.
The relevant ministries and directorates are listed under 1.2 System of Petroleum Ownership, above. All relevant websites related to the upstream and downstream sectors of ministries and directorates may be accessed at www.regjeringen.no.
In addition to the authorities described under 1.2 System of Petroleum Ownership, the competent directorate with regard to downstream natural gas transmission, distribution and storage regulations is the Norwegian Water Resources and Energy Directorate. Its website is: www.nve.no.
The licensee, owner or users (as the case may be) must fulfil certain requirements in order to obtain permits, pursuant to the provisions of the Pollution Control Act is applicable for certain discharge and emissions.
For further information, see under 2.2 Issuing Upstream Licences, above, relating to the conduct of area (SEA) and activity specific environmental impact assessment, as well as 2.2 Issuing Upstream Licences and 2.7 Requirements of a Licence Holder to Proceed to Development and Production on applicable pollution control legislation.
Pursuant to provisions of the Petroleum Act (PA) Chapter 2 and the Petroleum Regulations (PR) Chapter 2a the state conducts a comprehensive environmental impact assessments (EIA) prior to opening of acreage for petroleum activities (see 2.2 Issuing Upstream Licences, 2.7 Requirements for a Licence Holder to Proceed to Development and Production and 5.2 Environmental Obligations for a Major Petroleum Project, above). The EIAs cover the impact on the natural environment, industry-, infrastructure- and societal impacts, including employment. The resultant report is submitted to Stortinget for consideration and support of a recommendation on whether or not to open new areas for offshore petroleum activities.
The applicant for a facilities licence must before any development and production or facility licence is awarded, conduct an area- and activity-specific EIA (again, see 2.2 Issuing Upstream Licences, 2.7 Requirements for a Licence Holder to Proceed to Development and Production and 5.2 Environmental Obligations for a Major Petroleum Project above). The EIA is conducted in a fashion comparable to the initial or a subsequent specific EIA. It must be based on updated information and additional investigation as specified in an approved EIA programme.
The Petroleum Act (PA) and Petroleum Regulations (PR) regulating petroleum activities and facilities related to offshore petroleum resources contain a suite of special rules. The PA Chapter 7 contains specific rules on liability for pollution damage. The Petroleum Act Chapter 8 contains specific rules on special rules relating to compensation to Norwegian fishermen. The Petroleum Act Chapter 9 contains specific rules on safety.
Cessation of activities, decommissioning and potentially disposal of facilities are regulated by the provisions in the Petroleum Act (PA) Chapter 5 and those of the Petroleum Regulations (PR) Chapter 6. Wells are not considered facilities, so the plugging and abandonment of them are not included in a decommissioning plan before final decommissioning of production or use of related facilities. Norwegian decommissioning legislation is consistent with requirements that follow from ratified public international treaty obligations such as UNCLOS, the London Anti-dumping Convention and the OSPAR Convention.
A development plan pursuant to a production licence or a facilities licence must contain information of a general nature with regard to the decommissioning or potential removal of an installation.
There is a general requirement of removal of installations, but it is expected that certain gravity base concrete structure will be left in place because of the potential safety risk and negative environmental effects associated with removal. However, concrete foundations to steel structures have previously been removed and dumped inside Norwegian internal waters.
To date, submarine pipelines do not have to be removed. Flowlines and umbilicals connecting offshore installations within the same development area are normally considered part of installations and are thus required to be removed. Flowlines and umbilicals between installations located in different development areas or to onshore facilities are also normally removed.
The licensee holding a participating interest in an exclusive petroleum licence or the owner of a facility is obliged to submit a decommissioning plan no earlier than five years and no later than two years prior to planned cessation of petroleum (operations) activities or use of a facility. A plan may comprise one of more facilities in one or more areas.
If licensees or owner(s) fail to submit a decommissioning plan or implement an approved decommissioning plan the authorities may cause a third party to undertake the preparation of the plan or implement an approved plan at the risk, liability and cost of the licensee or owner.
Rules apply with regard to emissions to air and discharge to land or sea under the Pollution Control Act, including fiscal disincentives in the form of eg, the CO2 tax. The CO2 tax rate applied to offshore petroleum (operations) activities is higher than for non-offshore activities. There is also limitation of emissions to air of NOx and volatile components.
Regional and local government has no power with regard to oil or gas production volumes. (See comments in 2.10 Legal or Regulatory Restrictions on Production Rights.)
Norway has not opened for exploration or production of shale or other unconventional petroleum resources. In any case, these are expected to be very limited, as most of the Norwegian land territory is base rock.
There is only one LNG production project in Norway. The project is governed by the ordinary upstream petroleum regulatory regime (PA and PR) and tax regime (GTA and PSTA). A special project-specific solution granting the licensees an augmented uplift for tax purposes was established for this particular project.
Due to the structure of the regulatory regime governance is heavily resource management-oriented, standardised and with substantial direct non-carried state participation. The regime is considered, transparent, predicable and accountable. In contrast to most regimes, disputes between investors and regulatory authorities are subject to the ordinary courts. In disputes among themselves, investors may resort to arbitration or other conflict resolution mechanisms.
The standardised production licence and its annex the petroleum agreement are subject to Norwegian law. According to mandatory licence terms, all contracts relating to or arising out of petroleum (operations) activities pursuant to an exclusive petroleum licence shall be governed by Norwegian law and be in accordance with Norwegian contract traditions.
No fundamental changes to the specific upstream regulatory regime have been implemented in 2018 save for the further reduction to 22% of the corporate income tax rate and the correspondingly increase of the petroleum special tax rate to 54%. The shift of the tax rates between the GTA and the PTA benefits all business activities, including the downstream petroleum sector, which are not subject to the special upstream petroleum tax regime. The aggregate tax rate applicable to upstream petroleum activities remains the same at 78%. Amendments to the allowable uplift percentage applicable for the calculation of petroleum special tax was further reduced to 5.2 % in 2018, effective from 1 January 2019. A lesser adjustment was also made to Royal Decree 27 June 1997 Regulations relating to petroleum activities section 39 containing provisions on the calculation of the acreage fee, effective from 1 January 2019. Amendments to the PSTA Section 10 are under consideration by the MFIN. Before the adoption of any amendment to the regulations, a proposal will be circulated for public consultation and comment. Several other adjustments of general, not specific, upstream or downstream petroleum activities in specific applications were also made to the GTA in 2018.
Amendments to Act 17 June 2005 relating to working environment, working hours and employment protection, etc (Working Environment Act) amended rules generally applicable to activity subject to its jurisdiction relating to regulation of temporary versus permanent employment that will be applicable on certain offshore installations and vessel used for the purpose of upstream petroleum activities. The amendments enter into force on 1 July 2019. Act 13 March 1981 relating thereto was amended on 21 June 2019, effective 1 July 2019. The amendments are of a general nature and relate to the specification of administrative pecuniary penalties for violations of a number of environmental protection provisions. This is a rather new phenomenon as administrative penalties of this nature are a rare and rather novel occurrence in Norway as it has traditionally been regarded as a less efficient means to induce or enhance compliance.
Act 21 December 1963 No 12 (Continental Shelf Act) was amended in 2018. The amendments entered into force on 1 July 2019. The amendment affected the scope of the law as a new law regulating the exploration and production of sub-sea mineral resources, partly modelled on the 1996 PA, was enacted by Stortinget as Act 22 March 2019. No 7 (Seabed Minerals Act) enters into force on 1 July 2019. The amendment to the 1963 Continental Shelf Act with regard to offshore mining activities, which are not regulated by the 1996 PA or 1997 PR, does not affect the upstream petroleum regime in place.
There are also proposals for amendment to the Working Environment Act with regard to including certain support vessels previously excluded from the scope of the law. With regard to employment, crew or manning, and working environment conditions, such vessels are subject at present to maritime legislation.
Secondary decommissioning liability for petroleum assets in Norway – main features and mitigating measures in transactions
Upon cessation of petroleum activities, the licensees are responsible for the decommissioning of facilities. In respect of previously transferred licences, the former licensee (seller) has a secondary liability for the current licensees' decommissioning obligations. Furthermore, in the event of a sale of all the shares of or a controlling interest in a licensee, the former parent company has a secondary liability for the decommissioning obligations of its former subsidiary.
The parties to a transaction, be it a licence (asset) transaction or a share transaction, must carefully consider how to manage secondary decommissioning obligations. Although private agreements will not affect the mandatory obligations, the seller and the buyer may arrange an inter-party shift of the risk and cost exposure that follow from such rules.
This article provides an overview of the regulatory framework, different decommissioning security arrangement models and issues to consider when choosing between these alternatives.
Background - Regulatory Regime for Petroleum Activities on the NCS
The petroleum activities on the Norwegian Continental Shelf (the "NCS") are governed by a licencing system set out in the Norwegian Petroleum Act (the "PA"). According to the PA, the Norwegian State has the proprietary right to the subsea petroleum deposits on the NCS and an exclusive resource management right. The production licence is the cornerstone of the licencing system on the NCS, as it gives licensees an exclusive right to explore and produce petroleum, in addition to proprietary rights to the produced petroleum.
A production licence is awarded by the Ministry of Petroleum and Energy (the "MPE") to a group of eligible companies (licensees). The most important award criteria are technical competence and financial capacity. The MPE also appoints the operator, who carries out the day-to-day management of the licence on a "no gain-no loss" basis.
The joint licence holders form an unincorporated joint venture ("JV") governed by a standardised Joint Operating Agreement (the "JOA"). The JOA is imposed by the MPE as part of its licence award. The JOA governs the relationship between the JV partners in respect of their joint operations, and the operator's role and responsibilities.
Each JV partner holds an undivided interest in the JV's capital assets and rights and shall contribute to the funding of the joint activities in proportion to its participating interest in the JV. The licensees are liable for any decommissioning obligations imposed by the MPE and consequently, each JV partner has an obligation to fund the decommissioning activities in proportion to its participating interest.
In the internal relationship between the JV partners, each party is primarily liable in proportion to its participating interest (pro rata) and is secondarily jointly and severally liable for all obligations arising from the joint activities. If one JV partner fails to contribute to the funding of decommissioning activities or other joint activities, the other JV partners must cover the outstanding amounts of the defaulting party in proportion to their participating interests.
The liability of a JV partner under the JOA and the PA is not subject to any monetary limits or caps. As described in more detail below, the parent company of a licensee on the NCS is required to provide security in the form of a parent company guarantee for the licensee's decommissioning obligations to the Norwegian state and certain other financial obligations arising from the petroleum activities.
A participating interest in a licence may be transferred directly as an asset transfer or indirectly through the sale of shares in the company holding the participating interest. Such transfers require prior approval by the MPE and, additionally, a tax ruling by the Ministry of Finance (the "MOF"). No approval from JV partners is required as long as the JV has completed the mandatory work program set by the MPE, but the Norwegian State holds pre-emptive rights that may be exercised at any time.
Decomissioning Liability Pursuant to the Petroleum Act
Liability for licensees
The licensees must submit a decommissioning plan to the MPE prior to the expiration or surrender of the production licence, or before the use of a facility is permanently discontinued. The plan shall describe alternatives for the continued production or the removal/abandonment of the installations as appropriate.
The MPE does not formally approve the licensees' decommissioning plan. Instead, the MPE adopts an independent decision based on the detailed decommissioning obligations of the relevant licensees, which in turn are based on technical, environmental and safety considerations. The MPE's decision may differ from the licensees' plans and proposals. The MPE sets a time limit for the implementation of the decommissioning decision and may stipulate conditions in the decision.
On a case-by-case basis, the MPE may opt for complete or partial removal of the relevant facility, continued use as a host infrastructure for other licence groups or other non-petroleum specific uses or abandonment without removal. The scope of the decommissioning activities is largely at the MPE's discretion.
The licensees are responsible for carrying out and covering the costs of the decommissioning obligations imposed by the MPE. However, since decommissioning costs are tax deductible in accordance with the principles of the Petroleum Taxation Act (the "PTA"), the Norwegian state will, in practice, carry the majority of these costs. With a marginal tax rate of 78 percent, the licensees are de facto responsible for only 22 percent of the total decommissioning costs.
Secondary liability for former licensees
In the event of a transfer of a license interest, the transferring party will, as a rule, be formally released from all its obligations related to the transferred interest. The same obligations will be fully assumed by the transferee from the date of transfer. Depending on the circumstances, such transfers of duties may entail a change in counterparty risks for the Norwegian state and for the affected JV partners. In order to mitigate such risks, a secondary liability for decommissioning costs for former licensees was included in the PA in 2009.
Under the PA, a transferring party (former licensee) remains secondarily liable for the decommissioning obligations of the buyer (current licensee), to the Norwegian state and to the JV partners in the production licence. The statutory secondary liability applies only to asset transfers (transfers of a licence or participating interest in a licence) and does not include share transfers or other indirect transfers.
The former licensee is only secondarily liable for the financial obligations relating to the decommissioning activities, and not for the current licensees' obligation to carry out decommissioning. The liability applies only to costs incurred, which means that the former licensee is not required to pay in advance or accept cash call arrangements.
The secondary liability is limited to a proportional share (equal to the transferred licence interest) of the decommissioning costs for facilities that existed at the time of the licence transfer. Thus, the former licensee is not, unlike the current licensees, liable on a joint and several basis for decommissioning costs incurred by the relevant production licence. The secondary liability is further limited to the after-tax value of the relevant costs (currently 22%).
Secondary liability for former parent companies
The MPE regularly require licensees to provide financial security for fulfilment of their obligations to the Norwegian state and certain other liabilities incurred in connection with petroleum activities on the NCS. Such security may be required at the time of the award of a production licence, or at a later point in time. The practice of the MPE is to request licensees to provide security in the form of a parent company guarantee from its ultimate parent company, using a standard parent company guarantee template. The standard guarantee is non-negotiable and is unlimited in time and amount. The guarantee shall, inter alia, cover any decommissioning liabilities.
In case of a sale of all the shares of or a controlling interest in the subsidiary, the parent will normally be released from its obligations under the general parent company guarantee (relating to future liabilities). However, since 2016 the MPE has required exiting parent companies to provide a new and more limited guarantee to cover the former subsidiary's decommissioning liabilities. The new guarantee is based on a standard guarantee format prepared by the MPE and is for the benefit of the Norwegian state and the JV partners of the former subsidiary. The scope of the new guarantee mirrors the secondary liability the subsidiary would have had pursuant to the PA had it sold all its assets in the form a business sale.
Except under special circumstances, the MPE is expected to impose the new decommissioning guarantee requirements in all future share transactions involving transfers of controlling interests. In parallel with the limited guarantee, the new controlling shareholder of the subsidiary has to provide a standard parent company guarantee that covers all the liabilities of the subsidiary (as described above).
Protecting the Seller from Secondary Liability in Transactions
The parties (buyer and seller) in a licence transaction, a transaction relating to infrastructure assets (platforms, pipelines etc) or a transaction of the shares of a licenced company, must consider how to manage the decommissioning obligations. The mandatory requirements mentioned above will not be affected by private agreements, but the seller and the buyer may agree an inter-party shift of the risk and cost exposure that follows from mandatory rules.
Most often, the parties agree that the buyer should take over all risks and costs related to the decommissioning of transferred assets. Such arrangements may or may not include measures to secure the mandatory risk exposure related to the seller's secondary liability for decommissioning costs.
As an alternative, the parties may agree that the seller remains liable for all decommissioning costs. Typically, this will apply in situations where the seller is better equipped to deal with decommissioning risks and costs, or puts a lower price tag on such risks, or in situations where the backing of the seller is a prerequisite for the transaction being approved by the MPE. In such situations, a discussion point may be whether and how the seller should provide security to cover the buyer's exposure as the primary liable party for decommissioning costs under the PA. The parties may also agree to split the decommissioning liabilities, either by an amount or by a percentage. The latter solution may result in the need for mutual guarantees between the transacting parties.
The economic risk exposure attached to primary or secondary decommissioning liabilities will at all times be defined by the relationship between the estimated value of future petroleum production in the relevant field and the estimated future decommissioning costs. Potential exposure becomes actual exposure on the date when the estimated decommissioning costs exceed the estimated value of future production, ie the date on which the net present value of the field turns negative (the 'Negative NPV Date'). The cornerstone of any decommissioning security arrangement will be to reduce the secured party's risks in the period between the Negative NPV Date and the date on which all decommissioning work has been completed.
There are several decommissioning security arrangement models. The most commonly used models are discussed below, the assumption being that the buyer is ultimately responsible for the decommissioning costs.
Briefly on the need for security and the security arrangements commonly used on the NCS
The starting point for any decommissioning security arrangement is a clear obligation for the buyer to keep the seller free from any and all future costs, risks and liabilities relating to the decommissioning of transferred assets. This is normally included in the risk allocation and/or indemnity chapters of the Sale and Purchase Agreement (SPA).
However, the buyer's ability to meet its future obligations under the SPA will remain a risk for the seller. The buyer's future financial solidity may depend on several factors, such asglobal market developments, oil price developments, developments in the Norwegian oil and gas industry and how the buyer runs its business. Since removing offshore installations is a costly endeavour, security arrangements are often introduced for the benefit of the seller.
Commonly used security arrangements include parent company guarantees from the ultimate parent of the buyer, financial guarantees and cash deposits. For tax efficiency reasons (as discussed in more detail below), guarantee elements are sometimes embedded in the purchase price settlement mechanisms. The various arrangements all have positive and negative elements. Some arrangements may be “comfortable” for the seller, but expensive. Other promising mechanisms may have unwanted tax consequences or include the risk of MPE pushback.
Discussions relating to buyer guarantees often focus on finding the right balance between effectiveness of risk coverage and cost efficiency. Hence, from the seller's point of view, guarantee costs will always drain value from the transaction.
Decommissioning security agreement and other security regimes
The most common approach to dealing with decommissioning risks is to require the buyer to enter into a separate decommissioning security agreement (the 'DSA'). The DSA aims to establish a financial security regime that adequately deals with the lack of funds to cover the buyer's future decommissioning costs.
The Norwegian Oil and Gas Association (NOROG) has published a standard model DSA that is commonly used by the participants on the NCS, with various adaptations to fit the particularities of each individual transaction. The DSAis structured as a two-party agreement with two sets of separate model terms and conditions with different security regimes.
Under the first set of DSA terms and conditions, the buyer is required to procure a letter of credit ('LoC') from the date of completion of the SPA. The LoC should cover the full present (estimated) value of the future decommissioning costs included in the seller's alternative liability.
The seller may draw on the letter of credit, and settlement shall be on demand in certain circumstances related to either the buyer or the guarantee provider. This includes situations where the letter of credit is not renewed, the seller becomes insolvent or the bank that issued the letter of credit ceases to be an acceptable bank (ie falls below the credit rating threshold). The letter of credit remains effective until all relevant decommissioning work has been completed.
The second set of model terms and conditions has a step-up structure. Upon completion of the purchase agreement, the buyer shall provide a parent company guarantee to the seller that covers all potential future decommissioning costs. The parent company guarantee may be called on and settlement shall be on demand. This parent company guarantee shall remain effective as long as the buyer has any remaining decommissioning obligations.
If, at a later date, the parent company's credit rating falls below a certain threshold, the seller may require the buyer to procure an LoC. Compared to the LoC of the first model, the step-up model LoC will, in the period prior to the Negative NPV Date, only relate to a fraction of the estimated decommissioning costs (the after-tax value of such costs, ie 22% plus a margin). After the Negative NPV date, the LoC should cover the full estimated decommissioning costs.
A DSA or a separate step-up guarantee may be structured in several ways. One option is to reserve the credit quality assessment of the buyer group to one or more of the buyer's material producing asset(s). As long as the buyer maintains its participating interest in such material asset(s), the seller may require additional security only in the form of a parent company guarantee. The expected cash flow from the anchor asset will reduce any inherit credit risk. Should the buyer choose to sell the anchor asset or if the asset is unexpectedly closed down , the seller may require the buyer to provide additional security in the form of a LoC.
Purchase price regulations and other mechanisms
Some sellers prefer to manage decommissioning liability issues as part of the compensation regime of the SPA. This could, for example, be purchase price adjustment mechanisms that reflect future decommissioning risks. The obvious benefit of such an arrangement is that all settlements may take place on an after-tax basis under the special rules that apply to petroleum assets under the PTA. On the negative side, contingent settlements add complexity and in most cases will require approval from the MOF.
Price adjustment mechanisms may vary in structure. The general idea is that the price will be adjusted retroactively (ie increased or decreased) when future pre-determined milestones are reached. Relevant milestones could be the buyer's performance with respect to annual income, fulfilment of decommissioning obligations, credit ratings etc. Alternatively, the estimated value of future decommissioning costs could be included as an additional purchase price element. The additional element may be included in the consideration paid immediately prior to or upon completion or at a later point in time (deferred payment). If the seller is not made subject to any decommissioning liabilities, the additional purchase price element must be settled with the buyer (payment and repayment both taking place on an after-tax basis).
Other SPA mechanisms for handling credit exposure include governance restrictions. For example, the seller may bar the buyer from undertaking certain actions without the prior approval of the seller. Repurchase rights is another form of control. The seller will then have the opportunity of exploiting any residual value in the licence to cover or reduce the decommissioning costs.
Issues to consider when choosing a security model
As illustrated above, sellers may choose from a variety of options when assessing how to manage decommissioning costs. Several arguments and risk factors should be taken into account when choosing a strategy.
First, as a starting point, the credit worthiness of the buyer must be considered. Experience, financial depth and stability (of the buyer and its parent company) are all important factors. If the buyer has a portfolio of licences, then the credit risk must be considered in connection with the expected cash flow from production of all producing assets. Expected positive cash flow from fields in production will decrease the overall credit risk.
A second important factor is tax. While the seller's secondary liability following asset sales are based on an after-tax settlement (22% of incurred costs, see above), settlements from the buyer are a taxable income that must be grossed-up to a 100% pre-tax level. Similar tax inefficiencies apply to secondary liable parties following share transactions, where the deduction rights for 78% of the decommissioning costs may be lost. A key consideration in the structuring of any decommissioning arrangement is to ensure that tax benefits are not lost and that the gross-up of the financial guarantee costs is not unnecessarily high.
Third, the security regime will need to be adapted to the requirements of the MPE and the MOF. For example, price adjustment mechanisms involving contingent and/or deferred payments raise questions related to resource management and taxation, which are closely monitored by the MPE and the MOF. Therefore, when establishing price adjustment mechanisms, the seller must ensure that the agreed regime complies with applicable laws and regulations.
Furthermore, the security model must be adapted to the type and nature of the transaction. The step-up DSA may be suitable for the sale of single assets, but may be less helpful in respect of a portfolio of assets as it lacks substantial amendments. The model clause step-up mechanism would track the Negative NPV date for the entire portfolio, while substantial decommissioning obligations in single fields may accrue earlier.
In view of the increased complexity, tailored solutions or a combination of different standard solutions should be considered when a portfolio of licences is transferred. A complicating factor to be aware of is that the buyer may diversify the portfolio at a later point, ie sell and acquire assets.