Oil and Gas in Norway - an introduction

OIL AND GAS IN NORWAY

an introduction

Advoka�irmaet BAHR AS www.bahr.no

March 2024

Introduction

The petroleum industry is Norway's largest industry measured in terms of value crea�on, government revenues, investments and export value and a cornerstone for Norwegian social and economic development for the last decades. Norway is a small player in the global crude market with produc�on covering about two per cent of the global demand. However, Norway is the third largest exporter of natural gas in the world and Norway supplies about 25 per cent of the EU gas demand. In 2022, Norway replaced Russia as the European Union’s (the “EU”) leading natural gas supplier. Nearly all oil and gas produced on the Norwegian Con�nental Shelf (“NCS”) is exported, and combined, oil and gas equal about half of the total value of Norwegian export of goods. For this reason, oil and gas represent the most important export commodi�es for the Norwegian economy. Government income is secured by taxa�on and direct par�cipa�on in the petroleum ac�vi�es.

Macroeconomic indicators for the petroleum sector, 1971-2024:

(Source: www.norskpetroleum.no)

Since produc�on started in 1971, oil and gas have been produced from a total of 123 fields on the NCS. At the end of 2023, 92 fields were in produc�on: 67 in the North Sea, 23 in the Norwegian Sea and 2 in the Barents Sea. In 2023, 4 new fields were set in produc�on. Fi�een fields are currently under development. Many of the producing fields are ageing, but some of them s�ll have substan�al remaining reserves. Petroleum resources on the NCS have been es�mated to 15.6 billion standard cubic metres of oil equivalents. Around 55 per cent of the total discovered and es�mated undiscovered petroleum resources have so far been produced and sold

Recent developments and key events on the NCS

Energy security on the global agenda

Following Russia’s full-scale invasion of Ukraine on 24 February 2022, which ini�ated a war that received widespread public condemna�on interna�onally, the EU launched RePowerEU, a plan to make Europe independent from Russian fossil fuels by 2027. Before the Russian invasion of Ukraine, EU relied on Russia for around 40% of its natural gas and 27% of its oil consump�on. Almost two years later, in Q3 2023, EU’s import of Russian gas was down approximately one-third to 12%. The rapid reduc�on is partly

due to the gas producers on the NCS being able to increase their gas produc�on and Norway replacing Russia as the leading natural gas supplier to the EU.

The importance of energy security has been a key topic on the global agenda for the last years The energy prices rose drama�cally in 2022, where the price of natural gas in Europe hit an all-�me high in 2022 and remained high in 2023, although stabilizing somewhat by the end of the year As Norway already is a large supplier of oil and gas, and the demand for fossil fuels is increasing, Norway is likely to be important in securing energy supply to Europe in the coming years. In 2023, 233.2 million Sm3 of marketable oil equivalents were produced, a minor increase from 232.8 million Sm3 in 2022 due to startup of produc�on from new projects. The gas produc�on from the NCS was 5% lower than in 2022, corresponding to 117.3 billion Sm3, mainly due to extended maintenance ac�vi�es on the facili�es onshore. For the next few years, total produc�on on the Norwegian shelf is expected to increase somewhat, as the decline in produc�on from aging fields is expected to be lower than the produc�on from new fields that come on stream.

Historical and expected produc�on in Norway, 1970-2028:

(Source: www.norskpetroleum.no)

High

ac�vity

level in 2023

In 2022, 13 Plans for Development and Opera�ons (“PDOs”) were delivered to the Ministry of Energy (“MoE”), as well as several plans for projects where the aim is to increase the produc�on close to exis�ng fields or extend their life�me. These plans were approved in 2023, and only 1 PDO for Eirin was delivered to the MoE in 2023 following the wave of PDOs in 2022.

The high number of PDO’s submited in 2022 has been driven by the temporary tax regime adopted in 2020. The temporary tax regime was adopted during the early stages of Covid, when the oil price was record-low impac�ng expected ac�vity levels in the oil and gas industry and consequently also the service industry. The tax regime intended to s�mulate ac�vity and to preserve the Norwegian service industry, which employs a significant number of persons. The temporary tax regime allowed for immediate deduc�on of investments in the tax base for special tax, in addi�on to an upli� (an extra deduc�on in the special tax base), for all investments made pursuant to a PDO/Plans

for Installa�on and Opera�on (“PIO”) filed before 1 January 2023 (see further details in point 11).

Menon Economics has es�mated the aggregated investments under the temporary tax regime to approximately NOK 440 billion. According to a report by Rystad Energy, these investments are expected to yield revenues for the State in the vicinity of NOK 747 billion (in 2023 monetary values).

Considering the high ac�vity, the temporary tax regime can be said to have been successful and worked as intended. However, the temporary tax regime has also been heavily cri�cised as being too favourable, par�cularly considering the high petroleum prices during 2022 and 2023. As such, there is a risk that the upli� on future investments may be further reduced from the current level of 12.4%.

Four new fields were set in produc�on during 2023, being Fenja and Bauge in the Norwegian Sea, and Tommeliten A and Breidablikk in the North Sea. Also, Kobra East and Gekko (Alvheim field), Blåbjørn (Åsgard field) and Frosk (Bøyla field) were completed.

The explora�on ac�vity on the NCS was at the same level in 2023 as in 2022, which was a litle lower than in 2021, but at the same level as in 2020. In 2023, 34 explora�on wells were spudded, and 14 discoveries were made on the NCS. In the 2023 Awards in Predefined Areas (“APA”) round awarded in January 2024, 24 companies were awarded a total of 62 licenses, compared to 47 in 2022, consis�ng of 29 in the North Sea, 25 in the Norwegian Sea and 8 in the Barents Sea.

Par�cipants on the NCS

Following the introduc�on of several new policies in the first decade of 2000, the number of new par�cipants to the NCS substan�ally increased and the combined number of ac�ve companies trended upwards. In the last 10 years, that trend has shi�ed, and the number of par�cipants has been reduced from 56 in 2013 to 27 ac�ve explora�on and produc�on companies today. Several of the majors and u�lity companies have the last decade exited the NCS or converted to indirect ownership posi�ons. This have laid the founda�on for an ac�ve M&A market and the growth of several mid-sized companies, which have developed to be sizeable and important companies through acquisi�ons and organic growth. Mid-sized companies now hold a rela�vely larger share of produc�on and are ac�ve within explora�on, new developments and in the applica�on and award of new produc�on licenses.

Numbers of companies on the Norwegian con�nental shelf 2000-2023, by size:

(Source: www.norskpetroleum.no)

The Norwegian State’s takeover of Gassled

The Norwegian gas infrastructure is the world’s largest offshore network, as it comprises of around 8,800 kilometres of pipelines. Most of the gas transporta�on infrastructure is owned through the partnership Gassled, with slightly more than 50% direct or indirect State par�cipa�on. On 28 April 2023, the MoE published a press release informing that the Norwegian State intends to exercise its right to take over key gas transporta�on facili�es, upon the end of the licence period and that the State wants to have full State ownership of the central parts of the Norwegian gas transporta�on system. While the majority of the licences in Gassled expires in 2028, other licences have a longer �me limit and certain onshore installa�ons do not have a �me limit at all.

For the licences where compensa�on to the licence holders is required, the MoE has informed that the compensa�on shall be based on the future expected net income that the owners of the infrastructure will have from their ownership. The announcement raises several issues which will need to be resolved. Na�onalisa�on of private ownership in such scale is seldom in Western democracies. However, pursuant to sec�on 5-6 of the Petroleum Act, there has always been a right for the State to take over the licence holders’ fixed facili�es when the licence expires. With the certainty that the gas transporta�on licences will not be prolonged; the period un�l licence expiry would be a less than ideal period for ongoing projects and required investments, many of which will have a longer perspec�ve than the current licence period. Thus, in the interest of all stakeholders our expecta�on is that the State will aim of concluding this process as soon as possible through a nego�ated solu�on between the State and the current owners. The core issue in such discussion would be the value which should be compensated by the State. This raises several issues, including the valua�on of assets not subject to a licence period.

Climate li�ga�on and the oil & gas sector

Globally, judicial ac�ons addressing climate change are on the rise, with cases before both domes�c and interna�onal courts. These legal challenges, frequently based on human rights arguments, are increasingly influencing the framework of climate accountability. The industry should an�cipate increased legal scru�ny concerning

environmental impact assessments, governmental approvals, and compliance with interna�onal climate agreements.

In Norway, as seen globally, there has been an up�ck in climate li�ga�on. A notable example occurred in 2020 when the Supreme Court rendered a decision in a Climate Case brought forth by the non-governmental organiza�ons Greenpeace Nordic and Nature and Youth against the Norwegian State The plain�ffs ques�oned the validity of the award of explora�on and produc�on licenses in the Barents Sea's in the 23rd licensing round. The Court determined that the award did not infringe upon Sec�on 112 of the Cons�tu�on, which guarantees the right to a healthy environment, nor were any other human rights obliga�ons breached. On the argument that procedural errors were made, the Supreme Court dismissed the claim and ruled that it did not cons�tute a procedural error that combus�on emissions associated with petroleum produced from possible future fields (so-called Scope 3 emissions) were not assessed in the environmental impact assessment related to decision to open the areas awarded in the concession round. The Supreme Court noted that the net effect of Scope 3 emissions from Norwegian oil and gas produc�on is a complicated and disputed mater, and that the net effect of Norwegian petroleum produc�on could be posi�ve, neutral or nega�ve depending on the assump�ons. As such, the effects from the combined emissions from Norwegian oil and gas produc�on in general should be assessed together. It was for the MoE and government to decide whether these maters should be assessed as part of the general petroleum policy, or as part of the specific impact assessment. It was referenced that a broad poli�cal majority on several occasions has rejected proposals to reduce or stop Norwegian oil and gas produc�on by reference to the global CO2 emissions and that the mater has been thoroughly debated and assessed. The Supreme Court noted that the climate effects of the petroleum produc�on will be con�nuously poli�cally assessed - and will be subject to an environmental impact assessment in the event of an applica�on for a PDO. Thus, the Court concluded that no procedural error was present.

This Supreme Court ruling is currently under review by the European Court of Human Rights (ECtHR), with a decision pending as of March 2024.

Following the Supreme Court ruling, the same non-governmental organiza�ons, Greenpeace Nordic and Nature and Youth, ini�ated a second climate case. This �me, they challenged the State's approvals of the PDO for three selected fields. On 18 January 2024, the Oslo District Court invalidated the State's PDO approvals for the Breidablikk, Yggdrasil, and Tyrving fields. The Court found that it was a procedural error that the assessment of Scope 3 emissions had not been subjected to the formal requirements of an environmental impact assessment, referring to the EEA impact assessment direc�ve (2011/92/EU) and the Petroleum Regula�ons as interpreted in context of the Norwegian Cons�tu�on Sec�on 112. The Court further concluded that the procedural error led to invalidity as it was not a completely remote possibility that it could have impacted the decisions to approve the PDOs. Moreover, the District Court ruled in a preliminary injunc�on that the State is prohibited from awarding further licenses assuming a valid PDO for the relevant fields. The Norwegian State has appealed the ruling and the injunc�on, promp�ng the case to move forward to the court of appeal.

The oil companies with par�cipa�ng interests in the affected produc�on licenses are not par�es to the court case. Accordingly, the ruling has only direct effect for the State. It means that the PDOs are not invalidated in rela�on to the oil companies.

In a broader European context, the ECtHR is set to deliver judgments on three climate cases heard in 2023, that could significantly influence the future of climate li�ga�on. Among these, the case involving Norway Duarte Agos�nho et al. v. Portugal and Others – stands out due to its inclusion of numerous State defendants and could have implica�ons for the country’s oil and gas sector.

Energy transi�on and new industries

The transi�on to a carbon neutral society has wide implica�ons across all industries and also fuels the development of new industries.

To succeed with the goal of a carbon neutral society, the capture, u�lisa�on and storage of CO2 (“CCUS”) is required. An important ini�a�ve to progress CCUS was the approval of funding for “Longship” in 2020, being a full-chain carbon capture, transporta�on, and storage project, including the project Northern Lights. Northern Lights is a project which intends to transport captured and liquified CO2 by ship from the Eastern part to the Western part of Norway, and therea�er by pipeline to an offshore storage loca�on subsea in the North Sea for permanent storage. The development plan for the Northern Lights project, the storage part of the Longship carbon capture and storage project, was approved by the MoE in March 2021 and in 2022.

On 20 November 2023, Northern Lights and Yara Interna�onal signed a binding commercial transport and storage agreement, where the ambi�on is to capture and store 800,000 tonnes Co2 from 2025. The inten�on is that the CO2 will be liquefied and transported from the Netherlands by Northern Lights to be stored permanently on the NCS.

In April 2023, the MoE announced that Belgium and Norway had started formal nego�a�ons on a bilateral agreement on cross border transport and storage of CO2, following an MoU between the countries of 23 February 2022.

Prior to 2023, the MoE had awarded four permits for injec�on and storage of CO2 on the NCS, of which three are in the North Sea and one in the Barents Sea. The permits were awarded to Northern Lights, to Equinor, one group consis�ng of Equinor ASA, Horisont Energi AS and Vår Energi AS (Polaris), and another group consis�ng of Wintershall Dea Norge AS and CapeOmega AS.

In 2023, addi�onal three permits were awarded in the North Sea. In March 2023, one group consis�ng of Aker BP ASA and OMV (Norge) AS, and one group consis�ng of Wintershall Dea Norge AS and Altera Infrastructure Group through its subsidiary Stella Maris CCS AS, received two of the permits. In August 2023, Sval Energi AS, Storegga Norge AS and Neptune Energy Norge AS (now Vår Energi Norge AS) received the third permit.

The MoE has announced that addi�onal areas for injec�on and storage of CO2 on the NCS will be announced during 2024.

(Source: Illustraton CCUS, Gassnova, www.norskpetroleum.no)

Several projects for the electrifica�on of NCS installa�ons are underway, driven partly by the cost of CO2 emissions and the climate targets set by the oil and gas industry and the Climate Act. Today, the fields Troll, Gjøa, Ormen Lange, Valhall, Goliat, Mar�n Linge and Johan Sverdrup are supplied directly with onshore electricity. In addi�on, Vega, Duva and Nova are supplied with onshore electricity through Gjøa, and Hod through Valhall. Further, the fields Edvard Grieg, Ivar Aasen, Gina Krog, Solveig and Hanz receives power under an area-wide solu�on on the Utsira High in the North Sea, as a part of Johan Sverdrup’s second phase.

In December 2022, the MoE received plans for increased gas produc�on from Snøhvit and electrifica�on of Hammerfest LNG from Equinor ASA, Petoro AS, TotalEnergies EP Norge AS, Neptune Energy Norge AS and Wintershall Dea Norge AS, which is called “Snøhvit Future”. The transi�on to electrifica�on is an important measure to reduce the CO2 emissions from the produc�on of oil and gas. In August 2023, Equinor ASA and the Snøhvit partners received approval from the MoE to proceed with the project. The electrifica�on of the facility will start in 2030, two years later than what was proposed in the Snøhvit partners’ applica�on.

The plans currently adopted are expected to reduce CO2 emissions with 3.2 million tons per year. Other plans are under development, and if adopted; the CO2 emissions may be reduced with a total of 4.9 million tons, which would entail a reduc�on of nearly 40 per cent of the total emissions from the petroleum industry in 2019.

Electrifica�on of oil and gas installa�ons on the NCS has become an increasingly debated topic as domes�c electricity prices onshore rose sharply during 2022, and a deficit in domes�c renewable electricity produc�on is expected within the next few years.

As a partly related ini�a�ve, Equinor ASA has announced their aim to build a large floa�ng offshore wind farm outside of Bergen in 2027, to power the Troll and Oseberg fields. The project requires a special approval by the MoE. In 2023, Equinor ASA announced that the plans had been postponed partly due to increased costs.

In November 2022, the first turbine in the Hywind Tampen floa�ng offshore wind farm started its power produc�on, delivering power to the Gullfaks A pla�orm in the North Sea. As of August 2023, Hywind Tampen was in full opera�on, supplying Gullfaks and Snorre with power from offshore wind. The aim of the project is to replace one third of the gas-fired power with renewable wind power for the Snorre and Gullfaks field. Hywind Tampen is currently the world’s first floa�ng wind farm to power offshore oil and gas pla�orms. The project is expected to reduce CO2 emissions from the Snorre and Gullfaks fields with more than 200,000 tonnes per year. The project has been supported by Enova and the Business Sector’s NoX Fund by NOK 2.3 billion and NOK 566 million to s�mulate technology development with offshore wind and emission reduc�ons.

Addi�onal floa�ng and botom fixed offshore wind farms are expected to be developed over the next 7 to 10 years. A�er the opening of the areas Utsira Nord and Sørlige Nordsjø II in 2020, the government announced the rules for award of acreage for one 1.5 GW capacity project on Sørlige Nordsjø II and a qualita�ve award process for the award of three projects up to 1.5 GW (in aggregate) on the Utsira Nord area in March 2023. The announcement was later updated on 17 October 2023.

The area award process for Sørlige Nordsjø II consists of two key steps, where the first step includes a compe��ve prequalifica�on process based on a set of qualita�ve criteria. The deadline for submi�ng an applica�on to prequalify was set to 15 November 2023, and the MoE received applica�ons from seven par�cipants, including (i) Aker Offshore Wind, BP and Statkra�, (ii) Equinor and RWE, (iii) Hydroelectric Corpora�on, (iv) Mingyang Smart Energy (Chinese), (v) Norseman Wind (a consor�um with Norgesgruppen and EnBW (German)), (vi) Parkwind (Belgian) and Ingka (the Ikea group’s investment company), (vii) Shell, Lyse and Eviny. On 16 February 2024, the MoE announced that five of the seven par�cipants had been prequalified (not Hydroelectric Corpora�on and Mingyang Smart Energy) and that they would be invited to par�cipate in step two, which will be a monetary auc�on planned 18 March 2024.

For Utsira Nord, the three project areas will be awarded a�er a compe��ve process based on qualita�ve criteria, however, there will not be a prior pre-qualifica�on process as with Sørlige Nordsjø II. The plan is that the project with the highest score will be awarded its preferred area, with the project with the next best score being awarded its preferred area of the two remaining areas, and the third best project being awarded the last remaining area. The deadline for submission of applica�on was originally set to 1 September 2023. The MoE has however stated that they will revert with an updated deadline.

Green light for seabed minerals

On 9 January 2024, the Norwegian parliament decided to adopt the government’s proposal for opening an area for mineral ac�vi�es on the NCS. This implies that companies now can contribute to clarify whether there are mineral resources that are commercially atrac�ve, which also can be received in a sustainable manner.

The MoE has announced that it will begin the process of announcing areas for applica�ons and awarding extrac�on licenses in 2024, pursuant to the Norwegian Seabed Minerals Act.

The regulatory framework

The Norwegian Petroleum Act of 1996 (the “Petroleum Act ”) sets out the main regulatory framework for petroleum ac�vi�es on the NCS. The Petroleum Act is based on the principle that all petroleum deposits on the NCS are owned by the Norwegian State, and that the State can grant produc�on licenses allowing others to explore for and produce petroleum. Governmental control is further exercised through the requirement of approvals in all phases of petroleum ac�vi�es, from gathering of seismic data and explora�on drilling, to development, opera�on and decommissioning of oil installa�ons, as well as approval for the transfer of already granted produc�on licenses. The Petroleum Act is supplemented by other legisla�ons specifically rela�ng to petroleum ac�vi�es, such as the Petroleum Tax Act of 1975, as well as general legisla�on relevant to petroleum ac�vi�es such as the Working Environment Act of 2005 and the Pollu�on and Waste Act of 1981.

In addi�on, there is a significant volume of secondary regula�ons concerning different aspects for petroleum ac�vi�es.

The main regulatory bodies and State participation in petroleum activities1

The main regulatory body is the MoE, which has authority over most parts of the Petroleum Act including ownership regula�ons and licensing rounds. Some of these func�ons are delegated to the Norwegian Offshore Directorate. Major development projects and issues of fundamental importance must be approved by the Norwegian Parliament. The Ministry of Finance has authority for petroleum tax maters. The Norwegian Ocean Industry Authority is responsible for safety and HSE maters.

The Norwegian State has substan�al holdings in produc�on licences on the NCS through the State’s Direct Financial Interest (“SDFI”). The formal licensee for the SDFI assets is Petoro AS, a company wholly owned by the State. In addi�on, the State par�cipates through its ownership interests in Equinor ASA and Gassco AS. The later is a company wholly owned by the State which is the operator of the comprehensive gas transporta�on system on the NCS. The responsibility for managing the State’s direct and indirect par�cipa�on in the petroleum ac�vi�es through SDFI/Petoro and Equinor lies

1 On 1 January 2024,

with the Ministry of Trade, Industry and Fisheries – who also manage the State’s ownership interest in other en��es such as DNB, Norsk Hydro and Yara

Petroleum activity requires a production license

Companies wishing to produce petroleum on the NCS must hold a produc�on license, providing certain exclusive rights to perform petroleum ac�vi�es within the geographical area defined by the produc�on license

Produc�on licenses can be awarded to exis�ng oil companies on the NCS, or to new entrants that are prequalified to hold such licenses. The general policy is that petroleum ac�vi�es must be carried out by en��es that are able to contribute to the Norwegian petroleum industry beyond just financial par�cipa�on, and that the ac�vi�es are carried out in an efficient, competent, and responsible manner. Therefore, license awards and prequalifica�on require that the company can demonstrate sufficient technical, financial and Health, Safety and Environment (“HSE”) skills and resources. The prequalifica�on procedure for new entrants typically takes up to half a year. Guidelines for pre-qualifica�on are found on the web page of the Petroleum Directorate.

Licensing rounds

Produc�on licenses are awarded through licensing rounds. There are two different kinds of licensing rounds on the NCS. There is an annual system of Awards in Predefined Areas (“APA”) in mature parts of the NCS. The APA rounds were originally intended to ensure that areas close to exis�ng and planned infrastructure are available to the industry before exis�ng infrastructure shuts down Over �me, the APA area has been expanded and today the APA area comprises most of the open, accessible explora�on area on the Norwegian con�nental shelf. In addi�on to the APA system, ordinary licensing rounds are held - normally every second year (although the current government have stated that no such round will be ini�ated in this parliamentary term, as the 26th licensing round has been postponed un�l 2025). The ordinary rounds focus on fron�er areas that are less explored and where less exis�ng infrastructure has been built.

The MoE awards produc�on licenses based on the applica�ons submited. Relevant, objec�ve, non-discriminatory and announced criteria form the basis for these awards. Applicants can apply individually or as a group.

New produc�on licenses are awarded to a group of companies, that each will hold a par�cipa�ng interest in the license. The license grants the par�cipants exclusive rights to surveys, explora�on drilling and produc�on of petroleum within the geographical area covered by the license. The licensees become the owners of the petroleum that is produced, with each licensee being en�tled to a por�on of the petroleum corresponding to their par�cipa�ng interest in the license

Produc�on licenses are valid for an ini�al period (explora�on period) that can last for up to ten years. During this period, the work program determined by the license must be carried, typically consis�ng of geological/geophysical surveys or reprocessing, explora�on drilling and/or submital of a PDO. If all the licensees agree, the produc�on

license can be relinquished when the work commitment has been fulfilled. Licensees having sa�sfied the work commitment can demand that the produc�on license is extended for a period which typically is 30 years but may be up to 50 years in special circumstances

The produc�on licenses are registered in the Petroleum Registry which is an official and publicly available register that among other records ownership and encumbrances. Produc�on licenses can be mortgaged upon applica�on and approval from the MoE

Plans for Development and Operation (PDO)

If the licensees determines that it is commercially viable to develop a discovered field, the development shall be done in a prudent manner. The licensees are responsible for the development of new projects, but the development is subject to approval from the authori�es. The approval is provided on the background of a PDO submited to the MoE for approval. PDO’s for large and/or par�cularly important projects are presented to Parliament before the MoE’s approval. An important part of the PDO is an impact assessment which is submited for consulta�on to various bodies that could be affected by the specific development. The impact assessment shall assess how the development is expected to affect the environment, fisheries, and society in general. The processing of this assessment and the PDO itself is intended to ensure that the projects are prudent in terms of resource management, and that the consequences for other public interests are acceptable. The impact assessment is compulsory unless the licensees can document that the PDO is covered by a relevant exis�ng impact assessment. The MoE has expressed that the impact assessment shall include an assessment of the financial climate risks associated with the development. This entails an assessment of the economical profitability of the development based on future oil prices in a market/revised policy scenario compliant with the goals of the Paris Agreement. Furthermore, following up on the Supreme Court ruling in 2020 in the “climate lawsuit”, the MoE will as part of its approval process include an assessment of the climate effect of emissions from both produc�on and the use of petroleum produced from the field (Ccope 3 emissions). The adequacy of this procedural change is presently subject to judicial review. As detailed in the sec�on on climate li�ga�on above, on January 18, 2024, the Oslo District Court determined that the government's handling of these maters is inadequate. The Court mandated that detailed environmental impact assessments of the combus�on emissions associated with each oil field development must be conducted. The State has challenged the ruling, and it is scheduled for review in the court of appeals.

The petroleum ac�vi�es shall be conducted in a prudent manner to ensure that a high level of HSE can be maintained and developed throughout all phases, in line with the con�nuous technological and organisa�onal development. The licensees are responsible for pollu�on without regard for fault. This is referred to as strict liability.

Joint Operating Agreements

The license holders form a joint venture that is responsible for the petroleum ac�vi�es within the license area. The license group is required to enter into a Joint Opera�ng Agreement (“JOA”) which regulates the rights and obliga�ons for the joint venture within the specific license. The JOAs are standardized by a format that the MoE requires

all license holders to use. The MoE nominates one of the par�cipants in the license as the operator, which will be responsible for the opera�onal ac�vi�es authorised by the license. Major decisions are made by the management commitee where all license holders are represented and have vo�ng rights according to vo�ng rules set out in the license terms. Normally, a decision is made by the management commitee when at least two of the par�cipants that jointly represent at least 50 per cent of the par�cipa�ng interest vote in favour of a proposal. The par�cipants in the license have joint and several liability for the obliga�ons and liabili�es arising out of the license.

Licensees are required to provide a Parent Company Guarantee

The Petroleum Act sec�on 10-7 gives the MoE the right, at any �me, to demand adequate security for holders of produc�on licenses on the NCS. The authority pursuant to sec�on 10-7 is quite wide with regard to �ming and the nature of the security that can be required. However, in prac�ce the MoE requires licensees to provide an unlimited Parent Company Guarantee (“PCG”) for the benefit of the Norwegian State to secure all obliga�ons in rela�on to the petroleum ac�vi�es. The format and wording of the parent company guarantee is based on a standard template. This standard form is non-nego�able and is kept in a brief format. So far there have been no instances where the guarantee has been used in prac�ce, and there are therefore several issues where the interpreta�on is unclear. For instance, it is debated whether other par�cipants in a license can draw on the guarantee if another partner in the license defaults on its obliga�ons.

The main policy is that the MoE will require that the parent company guarantee is provided by the ul�mate parent company of the licensee. A company is considered a parent company if the company, directly and/or indirectly, owns or controls more than 50 per cent of the licensee. Thus, a company owning and/or controlling less than 50 per cent will normally not be required to issue a PCG. There are examples where the parent company guarantee has been issued by entities within a group that is not the ul�mate parent company. For corporate transac�ons, the current policy of the MoE is to return parent company guarantees if a shareholder ceases to have more than 50 per cent of the shares in the licensee.

Decommissioning liability

As a main rule, the Petroleum Act requires licensees to submit a cessa�on plan to the MoE two to five years before the licence expires or is relinquished, or before the use of a facility ceases. The cessa�on plan must have two main parts: an impact assessment and a disposal sec�on. The impact assessment provides an overview of the expected consequences of the disposal for the environment and other factors. The disposal part must include proposals for how cessa�on of petroleum ac�vi�es on a field can be accomplished. In addi�on to the Petroleum Act, the Oslo Paris Conven�on for the protec�on of the marine environment of the North- East Atlan�c (OSPAR) also governs disposal of facili�es. As a general principle under the OSPAR conven�on, facili�es cannot be abandoned on-site

It follows from the Petroleum Act that a seller of a par�cipa�ng interest in a produc�on license will remain secondary liable for decommissioning costs. The secondary liability applies to the seller’s share of installa�ons exis�ng at the �me of the transac�on and is a financial obliga�on to pay the (a�er tax) cost of the decommissioning if the buyer of the par�cipa�ng license fails to meet its obliga�ons. To protect the seller from such liability it is not uncommon to enter into decommissioning security agreements between the buyer and the seller, depending on the financial solidity of the par�es and the amount of decommissioning obliga�ons. In a corporate transac�on structured as a sale of a controlling interest in a Norwegian E&P en�ty, prac�se has now been established whereby the MoE generally require that the ul�mate selling parent company issue a parent company guarantee to the State establishing a comparable secondary liability for decommissioning obliga�ons of the target en�ty – see more on this in sec�on 13 below.

There is currently no prac�ce or requirement for general decommissioning security arrangements internally between the partners in a license.

The Norwegian Petroleum Tax System

The petroleum resources belong to the Norwegian State and the State secures its revenues through taxa�on, direct par�cipa�on in the licenses through Petoro and as a

shareholder in Equinor. Norway has no addi�onal produc�on sharing or royalty schemes but imposes fees on emission of CO2 and NOX

Companies par�cipa�ng in produc�on and pipeline transporta�on of petroleum on the NCS, are subject to the special petroleum tax regime with a combined effec�ve tax rate of 78% (the effec�ve tax rate is actually 78.004% but is referred to herein as 78%).

The petroleum tax consists of both the ordinary corporate tax, where the formal corporate tax rate is 22%, and the special petroleum tax, where the rate is 71.8%. However, since a calculated corporate tax may be deducted in the special tax base, the effec�ve corporate tax is only 6.2%.

The petroleum tax applies on a net profit level from all petroleum ac�vi�es subject to the special tax, not on a ring-fenced basis for each petroleum field. Losses generated by ac�vi�es not subject to the petroleum tax may as a general rule not be deducted from the special tax base, and there are limita�ons on the right to set off such non-petroleum losses against the ordinary corporate tax base of the petroleum tax. Thus, the petroleum tax is to a large extent ring-fenced to petroleum ac�vi�es.

Historically, petroleum investments were capitalised and depreciated on a straight-line basis for six years. In addi�on, the petroleum companies were en�tled to an extra investment deduc�on for specific investments in the special tax base (upli�).

Effec�ve from 1 January 2022, the special petroleum tax was changed to a cash flowbased model. In the special tax base, investments in pipeline and produc�on facili�es are fully deduc�ble in the year of investment. In the corporate tax basis, investments in pipeline and produc�on facili�es are capitalized and depreciated under the tradi�onal straight-line method at a rate of 16 2/3 per cent annually, i.e., depreca�on over 6 years. The deprecia�on may start as soon as the investment cost has been incurred.

The tax value of any losses in the special tax regime will be setled as a tax refund from the State as part of the annual tax assessment. The tax value of losses in the corporate tax must be carried forward (in nominal values without any interest compensa�on).

All costs related to the petroleum ac�vi�es are in principle deduc�ble in the petroleum tax bases. Financial costs are fully deduc�ble in the corporate tax base of the petroleum tax. Some of the financial costs may also be allocated to the special tax base pursuant to a specific formula based on remaining tax values of fixed assets in the special tax basis. However, due to the introduc�on of the cash flow tax in 2002, the tax value of fixed assets in the special tax basis will be minimal. Thus, the alloca�on of financial costs to the special tax base will in prac�ce be more or less phased out.

Norm prices can be imposed when calcula�ng taxable income from the sale of produced petroleum. The Petroleum Price Council (PPR) determines the norm price. The Council receives informa�on from and meets with companies before se�ng the final norm price. This norm price system applies to certain grades of crude oil and NGL. For gas, the actual sales price is used as the tax basis. However, related party transac�ons may be adjusted by the tax authori�es based on ordinary transfer pricing rules if the gas prices are not in line with the arm’s length principle.

In 2020, provisional tax changes were made to s�mulate investments in the petroleum sector. Such tax treatment will also comprise investments made pursuant to (A) a PDO/PIO filed before 1 January 2023 and (B) approved by the government a�er 12 May 2020, but before 1 January 2024 (but not investments made a�er the year of planned “first oil” as defined in the approved PDO/PIO). The main benefit of being subject to the temporary rules, is the right to calculate an upli� which is deduc�ble in the special tax basis. The upli� is currently 12.4% of the investment. Thus, if an investment of 100 is made, the taxpayer is allowed to reduce the special tax basis with a total of 112.4, equal to a tax value of 80.7 (112.4 x 71.8%).

Investments comprised by the provisional tax changes are capitalised and depreciated over 6 years in the corporate tax base, as under the ordinary petroleum tax rules. No upli� is applied to the corporate tax base.

Transactions and change of ownership

Par�cipa�ng interests in Norwegian petroleum licenses are transferrable. The par�cipa�ng interests can (except for some of the older licenses) be sold without the consent of the other license partners, provided that the compulsory work obliga�on set out in the license has been fulfilled. Prior to fulfilment of the work obliga�on the management commitee of the license must give its consent to an assignment. There are normally no pre-emp�on rights for the other private license partners pursuant to the JOAs, except in some of the older licenses. The Norwegian State/Petoro has a general right of pre-emp�on, but so far this has to our knowledge not been used in prac�ce. In a scenario with increased focus on securing energy supply to Europe, this provision should be assessed in rela�on to each individual transac�on.

Direct transfer of par�cipa�ng interests is subject to approval by the MoE pursuant to the Petroleum Act. The same applies for share transac�ons which according to law “may provide decisive control of a licensee possessing a par�cipa�ng interest in a licence”.

The MoE have stated that the wording shall be interpreted broadly, and that approval may be required for transac�ons where the buyer does not even achieve nega�ve control. Further, it s�pulated that any uncertainty with respect to the applicability of the requirement must be discussed with the MoE.

Approval by the Ministry of Finance is also required for the same transac�ons for tax purposes. The main principle is that transac�ons should be tax natural. Hence, in asset transac�ons (direct transfer of par�cipa�ng interests) the tax basis of deprecia�on and upli� related to the assets are transferred to the buyer (tax con�nuity). Further, the considera�on is not taxed as income for the seller and is, correspondingly, not deduc�ble for the buyer. Losses and unused upli� carried forward will as a rule remain with the seller. Share transac�ons will normally not trigger Norwegian tax.

Transac�ons can also trigger other regulatory approvals, such as approval from the MoE for change of operatorship or approval to create pledges over the license interests. The Norwegian Ocean Industry Authority can also require that new applica�ons are made with regard to HSE related permits if the transac�on changes the basis for exis�ng permits. Further, for certain transac�ons, an approval under the Norwegian Na�onal Security Act may be required.

It is a general principle that all petroleum ac�vi�es within a group are conducted through one single legal en�ty. Therefore, if an exis�ng company buys the shares of another company, the MoE will require that the businesses are combined into one single legal en�ty. If the two companies are par�cipants in the same licenses, the MoE may also require that the vo�ng rules are amended.

If a contemplated transac�on leads to a company acquiring 100 per cent ownership in a produc�on license, the MoE has in rela�on to certain transac�ons set as a requirement for its approval that the acquiring company divests a part of its par�cipa�ng interest in the relevant license.

The government’s current approach to companies exiting the NCS

Up un�l late 2017, it was possible to achieve a clean exit from the NCS by selling shares in a subsidiary that holds produc�on licenses. For share transac�ons there was no secondary liability for decommissioning, since a share transac�on does not imply a change of the legal en�ty holding the produc�on license. It was also the government’s policy to return the parent company guarantee when the shares were sold.

As many of the interna�onal majors have already exited the NCS, a concern for the government has been whether the new entrants will be able to meet future decommissioning costs. This prompted the government to revisit the policy of gran�ng companies a clean exit.

As from late 2017, the MoE’s policy has however been that they will consider imposing as a condi�on to approve the new owner that the selling shareholder undertakes to issue a new parent company guarantee where the seller remains secondary liable for exis�ng decommissioning obliga�ons.

The MoE has developed a standard template for this secondary liability decommissioning guarantee. As a result of this approach, share transac�ons and asset transac�ons are now treated more equally in terms of decommissioning obliga�ons. Several ques�ons arise rela�ng to this approach which has yet to be resolved, inter alia whether a payment under the new guarantee should be calculated as an amount preor post-tax.

Further information regarding Norwegian petroleum activities can be found here: https://www.norskpetroleum.no/en/

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OUR SERVICES

BAHR’s legal team has vast experience of working closely with a number of major players on the Norwegian Con�nental Shelf. We have a thorough understanding of the legal framework governing the industry. We advise in large transac�ons and represent companies in legal disputes. We also assist in connec�on with major development projects. Furthermore, we have comprehensive experience within the regulatory field including extensive government rela�ons. BAHR also has exper�se in petroleum taxa�on, appeals and li�ga�on of tax disputes. We represent several large oil companies in complex tax disputes before the tax assessment administra�on and the courts.

CERTAIN RECENT MATTERS WITHIN THE OIL AND GAS SECTOR

• Assis�ng Neptune Energy and its shareholders on the sale of Neptune Energy Norge AS to Vår Energi and the parallel transfer of the Neptune Energy group to Eni Interna�onal B.V..

• Assis�ng Aker ASA and Aker BP ASA with the notable acquisi�on of and merger with Lundin Energy Norway AS.

• Assis�ng Sval Energi AS with several transforming transac�ons, including inter alia (i) the acquisi�on of Spirit Energy Norway AS’s key assets, (ii) the acquisi�on of Equinor Energy AS’ 19% par�cipa�ng interest in the Mar�n Linge Unit and Equinor’s en�re par�cipa�ng interest in the Greater Ekofisk Area and (iii) the acquisi�on of and subsequent consolida�on with Suncor Energy Norge AS.

• Advise on contract strategy, contract development, nego�a�ons, and project follow up for key contracts relevant for the E&P industry.

• Assis�ng INEOS on the sale of the en�re Norwegian E&P business to PGNiG Upstream Norway AS.

• Assis�ng several E&P companies with strategic advice in rela�on to the development of carbon capture and storage (CCS) solu�ons, including contractual maters, coopera�on agreements and regulatory issues.

• Ac�ng as counsel for HitecVision in an interna�onal oil and gas arbitra�on against Tullow Oil.

• Advising in rela�on to major uni�za�on processes.

• Assis�ng several oil and gas companies with tax advice, including assistance with ongoing disputes before the tax assessment administra�on and the courts.

• Ac�ng as counsel in rela�on to a dispute related to a �e-in agreement on the Norwegian Con�nental Shelf.

• Assis�ng in rela�on to several substan�al gas price review arbitra�on processes.

• Assis�ng in several major infrastructure and pipeline transac�ons, including with the sale and purchase of Sval’s interests in the gas transporta�on infrastructure Polarled and Gassled to Hav Energy.

EDITORIAL COMMITTEE

For more informa�on, please contact:

Stig K. Engelhart Partner

M: +47 47 01 11 12 E: skl@bahr.no

Fanny B. Estensen Associate

M: +47 91 12 11 57 E: faest@bahr.no

Trond Lingaas Specialist Partner

M: +47 92 04 46 74 E: troli@bahr.no

Julian Davidsen Associate

M: +47 97 61 91 25 E: judav@bahr.no

Joachim M. Bjerke Partner

M: +47 90 50 57 77 E: jmb@bahr.no

Augusta L. Remøy Associate

M: +47 90 08 05 33 E: aurem@bahr.no

Important information

This pamphlet contains informa�on in summary form and is therefore intended for general guidance only. It is not intended to be relied upon as legal advice or be a subs�tute for detailed research or the exercise of professional judgement. Please refer to your advisors for specific advice. BAHR will not accept any responsibility for loss occasioned to any person ac�ng or refraining from ac�on as a result of any material in this newsleter. Advokatfirmaet BAHR AS