Norway: Oil & Gas

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This country-specific Q&A provides an overview of the legal framework and key issues surrounding oil and gas law in Norway.

This Q&A is part of the global guide to Oil & Gas.

For a full list of jurisdictional Q&As visit http://www.inhouselawyer.co.uk/index.php/practice-areas/oil-and-gas

  1. Does your jurisdiction have an established upstream oil and gas industry? What are the current production levels and what are the oil and gas reserve levels?

    Norway has since the 1965 first licencing round had offshore upstream petroleum exploration and production activities. Commercial production started in the early 1970s. For several years, Norway has been a substantial producer of oil & gas. In total 7,3 billion standard cubic meter oil equivalents (Sm3 o.e.) has been produced. Oil production peaked in 2001 with 3,4 mboed. The total annual NCS production peaked in 2004 with 264,2 o.e. Natural gas production may not yet have peaked, but has not made up for the decline in liquids production. Remaining resources still to be produced are estimated by the Norwegian Petroleum Directorate (NPD) to be approx. 8, 3 billion Sm3 o.e.

    Norway is still a significant exporter of liquids with approx. 1.9 mboed (crude oil, LPG and condensates) exported. Annually more than 120 BCM (billion standard cubic meter) of natural gas is exported predominantly via large submarine pipelines to the European market, including the United Kingdom. A modest LNG production plant in located on the mainland north of the Arctic Circle. Very small volumes of mostly imported hydrocarbon products primarily for the transportation sector are consumed. Only two small refineries operate. Domestic market use of natural gas represents only about 1.5% of annual natural gas production.

  2. How are rights to explore and exploit oil and gas resources granted? Please provide a brief overview of the structure of the regulatory regime for upstream oil and gas. Is the regime the same for both onshore and offshore?

    Norway exercises jurisdiction over significant petroleum resources located in the seabed of the Norwegian continental shelf (NCS). Exploration and production activities related to these resources are governed by the 1996 Petroleum Act, supplemented by regulations (Royal Decrees, Ministry or Directorate decisions outlining generally applicable rules) and a dedicated gradually developed concessionary regime that has been in place since 1965. The standardised production licence is the core petroleum rights documents awarded pursuant to public administrative law and is not a contract. The conditions for award and the procedure implemented for competitive bidding prior to an award of production licences are consistent with Norway's EEA obligations and compliant with EU internal market rules including the 1994 EU Hydrocarbons Licencing Directive. The production licence requires licensees to enter into mandatory standardised joint operating agreement and accounting agreement establishing an unincorporated joint venture for each production licence.

    Petroleum resources in the subsoil of on mainland Norway and any associated activities are regulated by the 1973 Land Petroleum Act. As most of the Norwegian mainland is without sedimentary rocks no activities have to date been conducted on the Norwegian mainland. Any activities related to petroleum within the territory of Spitsbergen is regulated by Norwegian law and jurisdiction expressed primarily through a 1925 Royal Decree – Bergverksordningen, established pursuant to the 1920 Svalbard treaty (entry into force in 1925). Very strict environmental regulations apply for most economic activity due to the sensitive Arctic environment. Only limited exploration activities have been undertaken at Svalbard and no commercial production.

  3. What are the key features of the licence/production sharing contract/concession/other pursuant to which oil and gas companies undertake oil and gas exploration and exploitation?

    The production licences extends exclusive right to licences to perform exploration drilling and subject to approval of a development plan the production of petroleum. The production licences is therefore by far the most important of the licences awarded by the authorities. Production licences are either awarded for predefined areas (APA-Rounds) on an annual basis or by numbered licencing rounds, lately appearing regularly and bi-annually. The numbered bid rounds include acreage covering unexplored acreage or acreage limited previous activity.

    The production licence contains standardised terms and conditions of which normally only the identification of licensees with their respective participating interest and the appointed operator vary. They have been rather uniform since their introduction in 1965, with a fundamental shift in 1972 when Norway introduced state participation. Their content are not negotiated and the production licence itself usually do not extend beyond 5-7 pages. Production licences are awarded initially for up to 10 years, normally for around 8 years and may be extended for commercial discoveries for up to 50 years, normally up to 30 years. At Government's discretion direct state participation managed by Petoro AS (a wholly State owned licence portfolio manager) may be included in production licences.

    Each production licence may also vary with regard to acreage specific limitation to activities due to environmental considerations and for APA licences an accelerated decision-making procedure for licensees to retain acreage. Enclosed and forming an integral part of the production licence is the petroleum agreement
    A facilities licence may be awarded subject to application for the construction, placement use and operation of offshore facilities for the production of exploitation of offshore petroleum resources when such facilities are not comprised by a development plan for a commercial petroleum deposit. Facilities licences are normally used for large projects servicing several production licences such the large diameter natural gas and liquids submarine landing pipelines. A facilities licence may include state participation.

    The 3-year non-exclusive exploration licence is awarded for allowing collection of data. The exploration licence entail shallow drilling for calibration purposes. An exploration licence does not give any preferential position or privileges in resolution to the award of a production licence. Exploration licences do not have state participation. If the authorities wishes to collect data beyond what is received from licensees they do so independently pursuant to the material provisions of the law. For data collection by the authorities no exploration licence is issued, but any contract, entered into will be on standard terms comparable with exploration licence operative terms. The authorities does not make use of commercial companies to promote acreage or sell data collected.

    Data collected under any petroleum licence must be shared with the Norwegian authorities for their internal use and publication of statistics at no cost to the authorities. After the expiry data confidentially pursuant to law, the authorities may share such data with the public or include such data in data packages.

  4. Are there any unconventional hydrocarbon resources (such as shale gas) being exploited and is there a separate regulatory regime for unconventionals?

    To date there has not been awarded any licences related to unconventional oil or gas resources on the NCS or on the Norwegian main land. The 1996 Petroleum Act and the 1973 land petroleum Act do not specifically address conventional resources. Some activities related to coal seam methane has been explored as Svalbard under the special Svalbard regime.

  5. Who are the key regulators for the upstream oil and gas industry?

    The Ministry of Petroleum and Energy (MPE) headed by a Cabinet Minister is the central upstream operations regulator in charge of petroleum resource management and upstream facilities operations. Its responsibility comprises resources, facilities and operations on the Norwegian Con¬tinental Shelf (NCS) and on the Norwegian mainland. It also includes activities outside the NCS when consistent with public international law, such as in relation transboundary fields subject to treaties and the gas and liquids trunk export pipelines to the UK and the European continent. The MPE is not in charge of Svalbard activities. The MPE is the appeal body for any appeals lodged against decisions taken by the Norm Price Board stipulation of Norm Prices applied to the specific petroleum fiscal regime.

  6. Is the government directly involved in the upstream oil and gas industry? Is there a government-owned oil and gas company?

    The MPE is in charge of and man¬ages the state’s participation (SDFI) in production- and facilities licences, the SDFI upstream interest management company Petoro AS, the gas landing pipe-line-system operator Gassco AS. Petoro AS is a management company and cannot be appointed operator. Gassco AS is a gas pipeline system-operator. Gassco AS cannot own any facilities, hold production lice and facility licence rights or own volumes of natural gas. MPE also looks after the state’s interest as shareholder in Statoil ASA, now a partly privatised and listed operative oil company. The MPE is in charge of the Petroleum Insurance Fund insuring state assets in the upstream sector

  7. Are there any special requirements for or restrictions on participation in the upstream oil and gas industry by foreign oil and gas companies?

    Objective prequalification criteria applies for those entities wishing to become production licensees or operators for a production licence. A pre-qualification procedure has been established. Facilities licences and operators may be individually assessed dependent on the application for the facilities licence. Only Gassco AS may be the Operator of Gassled the export landing natural gas submarine pipeline system. Other pipelines operating under a facilities licence, including all liquids pipelines, will normally have one of the operators of a production licence making use of the pipeline, appointed as pipeline operator when such an individual pipeline or other facility is not part of Gassled.

  8. What are the key features of the environmental and health and safety regime that applies to upstream oil and gas activities?

  9. How does the government derive value from oil and gas resources (royalties/production sharing/taxes)? Are there any special tax deductions or incentives offered?

  10. Are there any restrictions on export, local content obligations or domestic supply obligations?

  11. Does the regulatory regime include any specific decommissioning obligations?

  12. What is the regulatory regime that applies to the construction and operation of offshore and onshore oil and gas pipelines?

  13. What is the regulatory regime that applies to LNG liquefaction and LNG receiving terminals? Are there any such terminals in your jurisdiction?

    LNG facilities that form an integral part of the upstream production are subject to approval under the Petroleum Act of 1996 by the authorities of a Plan for development and operation of the facilities. Other permits for construction, operating and decommissioning is also required based on other laws.
    The only LNG production facility in Norway is the Snøhvit LNG project, which was constructed to exploit the resources of three gas fields in the Barents Sea: Snøhvit, Albatross and Askeladd. There are a few small-scale LNG production facilities in the south of Norway serving the local market consumption.

  14. What is the regulatory regime that applies to gas storage (not LNG)? Are there any gas storage facilities in your jurisdiction?

    Storage of natural gas is regulated by the Act on common rules for the internal market in natural gas of 2002 (Natural Gas Act 2002 – NGA 2002). All storage facilities in Norway are subject to law compliant with the rules of the EU's third energy package. However, if the storage facilities are part of an upstream development, the Petroleum Act of 1996 will apply also for the storage.

    Except for some minor onshore LNG gas storage facilities, there are no onshore natural gas storage facilities. There are no regasification facilities in Norway. The use of natural gas is mainly for export or reinjected in reservoirs for pressure maintenance or as temporary storage. Such reinjection forms a core component of the Norwegian resource management philosophy and enables improved or enhanced oil recovery.

  15. Is there a gas transmission and distribution system in your jurisdiction? How is gas distribution and transmission infrastructure owned and regulated? Is there a third party access regime?

    There is a gas transmission system on the Norwegian Continental Shelf through pipelines from the various production fields to onshore facilities. "Wet gas" and NGLs are conveyed by pipelines to onshore intermediate or final receiving terminals. Dry gas is exported to markets in UK and continental Europe, mostly by direct landing submarine pipelines.

    Gassco AS the system operator of Gassled the gas landing and export pipeline system is wholly owned by the State. Gassco's operator and system functions are regulated by law, including conditions for access to the system, reservation of capacity, booking of volumes and tariffs. Gassco's tasks also include developing new infrastructure, managing the gas transport system's capacity coordinating and managing the gas volumes through the pipeline network and to markets.

    Gassled is a regulated unincorporated joint venture that owns the majority of the gas export facilities on the Norwegian Continental Shelf such as submarine pipelines, onshore intermediate processing facilities and ultimate receiving terminals in the UK and on the European Continent. The infrastructure is used by anyone with a need to transport Norwegian gas. Gassled has no employees, and is organised through various committees with specific tasks.

    The Gassled system is a natural monopoly subject to detailed regulations consistent with EU internal energy market rules. To promote sound resource management, the transportation tariffs are set to permit utility rate of return on investments in the transportation system, but such that any excess returns from oil and gas production are derived from the fields. The gas owners or shippers have access to capacity in the system based on the need for gas transport. Capacity rights can be transferred between shippers.

  16. Is there a competitive and privatised downstream gas market or is gas supplied to end-customers by one or more incumbent/government-owned suppliers? Can customers choose their supplier?

    Subject to material and procedural rules pursuant to law for obtaining and operating downstream transmission, distribution, regasification or storage facilities, there are no limitations on who may engage in the downstream natural gas market. Some natural gas wholly owned by regional authorities are vertically integrated. To all undertakings, vertical unbundling principles are enforced towards gas suppliers that operate in the market as transmission system operators providing natural gas to end customers.

  17. How is the downstream gas market regulated?

    The downstream gas market is regulated by the Act on common rules for the internal market in natural gas of 2002 (Natural Gas Act 2002 – NGA 2002). The NGA 2002 is applicable for all activities related to natural gas, unless the Petroleum Act of 1996 applies. For the downstream gas market, the NGA 2002 will serve as the regulatory framework also after the implementation of EU's third internal energy market package, effective from November 1, 2019.

    The regulatory regime under the NGA 2002 is based on a system where the Ministry of Petroleum and Energy (MPE) appoints transmission, distribution, storage and LNF operators based on an individual decision. Each undertaking that owns a transmission system shall act as a system operator under the NGA 2002. The MPE may issue regulations regarding access for natural gas enterprises and customers to such systems on objective and non-discriminating terms.

    An enterprise that operates or have direct or indirect control over a unit that produce or supply natural gas to the market, may not own or run a transmission system or have any control over or have any rights in an entity that owns a transmission system.

  18. Have there been any significant recent changes in government policy and regulation in relation to the oil and gas industry?

    No.

  19. What key challenges have been identified by the government and/or industry in relation to your jurisdiction’s oil and gas industry?

    The government emphasises that the primary objective within the oil and gas industry is to maintain a steady and long-term policy and external conditions for the industry to cater for long-term profitable production of oil and gas. The industry is continuously changing and particularly since the fall in oil prices in 2014 substantial processes for changes and improved efficiency are ongoing. Such processes are complex and implemented progressively and may impose risk for HSE consequences. Development of new technology, including by digitalization, is important to achieve improvement within safety and efficiency in the industry. Continuous improvement within HSE is addressed as key challenge during periods with major changes and demands for improved efficiency. The government expects that the industry focus on maintenance of adequate resources, competence building and recruitment through processes of changes and innovations.

  20. Are there any policies or regulatory requirements relating to the oil and gas industry which reflect/implement the global trend towards the low-carbon energy transition?

    Regulations relating quotas and trade in quota for emission of greenhouse gas together with CO2-tax remains the main regulatory instruments to enforce strict environmental requirements. Additionally, the functional regulatory requirements impose obligation on licensees systematically to improve performance by use of best available technology. New production projects are increasingly required to provide offshore facilities with electricity generated by hydropower. Recent development within carbon capture and storage is identified by the industry as technically possible and achievable contribution to reduced emission of climate gas.