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EUROPEAN ENERGY HANDBOOK

A SURVEY OF THE LEGAL FRAMEWORK AND CURRENT ISSUES IN THE EUROPEAN ENERGY SECTOR

LEGAL GUIDE TENTH EDITION

2017

Third Energy PackageThroughout this publication, we refer to the two Directives and three Regulations adopted by the European Council and the Parliament on 13 July 2009 as the “Third Energy Package”. For ease of reference, the Directives and Regulations adopted as part of the Third Energy Package: EU Directives 2009/72/EC, 2009/73/EC and Regulations (EC) No 713/2009, No 714/2009 and No 715/2009 are referred to as the “Third Electricity Directive”, the "Third Gas Directive”, the “ACER Regulation”, the “Electricity Regulation” and the “Gas Regulation”, respectively. Where the context so requires, we refer collectively to the two Directives as the “Third Electricity and Gas Directives” and to the Regulations as the “Electricity and Gas Regulations”, as appropriate.

Climate Change PackageWe refer to the four Directives, one Regulation and one Decision adopted by the European Parliament on 17 December 2008 and the European Council on 6 April 2009 as the “Climate Change Package”. For ease of reference, throughout this publication, we refer to EU Directives 2009/29/EC, 2009/28/EC, 2009/31/EC and 2009/30/EC as the “New EU ETS Directive”, the “Renewable Energy Directive”, the “CCS Directive” and the “Biofuel Directive” respectively. Further, we refer to EU Decision No 406/2009/EC and Regulation (EC) No 443/2009 as the “GHG Reduction Decision” and the “Emissions Standards Regulation”, respectively.

Where required, we have referred to the previous internal energy market directives 1996/92/EC and 1998/30/EC as the "First Electricity Directive" and the "First Gas Directive", respectively and to Directives 2003/54/EC and 2003/55/EC as the "Second Electricity Directive" and the "Second Gas Directive", respectively.

Throughout the publication, we refer to Transmission System Operators as “TSO” and to Distribution System Operators as “DSO”.

We use the following abbreviations for the various unbundling models:

FOU: Full Ownership Unbundling

ITO: Independent Transport Operator

ISO: Independent System Operator

Legal advicePlease note that the content of this publication does not constitute legal advice and should not be relied on as such. Specific advice should be sought about your specific circumstances. The deadline for the submission of chapters was 31 March 2017.

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Energy policyIn April 2016, the Norwegian government presented a white paper on energy policy: 'Power for change – an energy policy towards 2030'. The main message of this paper is that security of supply, consequences on the climate, and economic growth must be considered together to ensure efficient and climate-friendly energy supply. The energy policies will focus on four areas:

•• Enhanced security of supply based on market solutions that enhance the flexibility of the energy system; strengthened Nordic energy cooperation; better coordination between transmission, consumption and production; new technology; and the use of smart management systems.

•• Efficient and profitable production of renewables through the development and use of new technology for renewable energy; stronger integration with other energy markets to maintain the value of Norwegian renewable resources through increased connections with European energy markets; opening the ability to own and operate interconnectors out to players other than the state-owned TSO Statnett; repealing the green certificate system, and making the licensing process more efficient.

•• More efficient and climate-friendly use of energy through supporting the development of new energy and climate solutions, in particular within the transport and industry sectors.

•• Economic growth and value creation through efficient use of profitable renewable resources, and the introduction of new legislation to enable industrial owners of hydropower to access predictable supplies in the future.

Trends in the energy marketThe Norwegian electricity market has been facing low power prices over a long period of time. This not only challenges the dividend policies of the producers, which in turn threatens necessary investments and reduces operational leeway for local municipalities; it also endangers investments in grid facilities.

At the same time, Norwegian grid companies need to invest huge sums in the maintenance and upgrade of existing transmission capcity, as well as the development of new such capacity in the coming years. TSO Statnett SF will be in charge of the largest investment plans through its Grid Development Plan.

Consultations by the regulator A number of consultation processes are currently ongoing or were recently finalised by the enactment of proposed changes, of which the most important are briefly mentioned below:

•• As of 1 January 2017, an amendment was made to the Energy Act that allows players other than Statnett, the TSO, to obtain a licence to build and operate interconnectors. The NorthConnect project, a direct submarine power cable between Norway and Scotland, could be the first project in which private parties own and operate the Norwegian part of an interconnector.

•• Amendments to the Act relating to el-certificates have been proposed with respect to the el-certificate curve in the coming calculation years. The changes will bring the curve down, ensure consistency with the Swedish regime (which is integrated with the Norwegian system), and provide the Ministry of Petroleum and Energy with the authority to adjust the curve in regulations. Changes to the el-certificates will also mean that all certificates, whether they are issues in Norway or Sweden, should be tradeable in a Swedish continuation of the scheme, ensuring the certificate's validity in both countries.

•• Amendments to the Water Resource Act have been proposed, amongst other things to provide the municipalities with the authority to grant concessions for small hydro power production facilities (up to 1MW installed capacity).

•• Taking effect from the income year 2015, the new rules on depreciation of wind farms was adopted 17 June 2016; the legislation now stipulates a five year straight line depreciation rule.

Carbon capture and storageThe Norwegian government has developed a strategy for CCS, with the aim of identifying measures to promote technology development and to reduce the costs of CCS. A feasibility study report presented in July 2016 shows that realising a full-scale CCS chain in Norway by 2022 is possible and at lower costs than for projects considered in Norway earlier.

The government's CCS-policies span across a broad range of measures including research, development and demonstration (for example through the existing Technology Center Mongstad), realising a full-scale CCS-facility, transport, storage and alternative use of CO2 and international co-operation for promoting CCS.

Energy law in NorwayRecent developments in the Norwegian energy market

Karl Erik Navestad and Dag Erlend Henriksen, partners, Arntzen de Besche Advokatfirma AS, Oslo

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Part of the CCS-strategy is further support for CLIMIT, the Norwegian research centres for climate-friendly energy (FME), and international research activities.

E&P transactionsThe NCS has seen several asset and share transactions in the last 12 months, suggesting a trend of consolidation of oil companies and of the exit of majors. The transaction making the most headlines in 2016 has been the merger of Det norske oljeselskap and BP Norge, creating a new large player on the NCS: AkerBP. Behind the still dominant Statoil, the two smaller players Lundin Norway and AkerBP have grown as challengers and have taken active roles on the NCS, both signalling the intent to lead. While Lundin has made its reputation as an oil finder, most prominently by discovering the giant Johan Sverdrup field, AkerBP has carried out several transactions which have strengthened its position, in addition to commencing production from its first operated field development, the Ivar Aasen field. In what many see as a step towards further consolidation, Statoil increased its shareholding in Lundin to 20% in 2016. At the same time, many foreign-based majors are looking to divest assets or even exit the NCS. However, sellers and buyers are still struggling to align price expectations, and so far of the majors only BP has been successful in its efforts to divest.

The impact of low oil prices on the Norwegian upstream and oil services sectorAlthough in the last months of 2016 the price of oil was around 50 USD/barrel, which might suggest some degree of stability after a long period of price decline, the level of activity on the NCS remains depressed. Exploration activity has reduced significantly and investment in field development is expected to continue to decline. Oil companies are still looking to reduce investment exposure, leading to work obligations being postponed and some production licences handed back to the State. The reduced appetite for exploration also strongly affects the Norwegian oil service industry, including drilling rig owners and service and supply vessel owners. Many employees have been laid off, and many companies forced into financial restructuring. Although older rigs are increasingly being scrapped, a significant surplus capacity has been built up over many years while the demand looks to remain low. However, some projects are still being carried out, and there is some optimism related to possible field development in the Barents Sea, particularly the Johan Castberg and Alta/Gotha discoveries.

Gassled tariffsThrough an amendment to the Tariff Regulation in June 2013, the regulated tariffs for the use of the upstream gas pipeline network at the Norwegian continental shelf (owned by Gassled joint venture) were reduced by 90%. The reduction applies for capacity reservations made after 1 July 2013 for transportation after 1 October 2016. The decrease in the cost for transportation and processing of natural gas is considered to strengthen the incentives for exploration and development of marginal fields, and was made to promote resource management. The government was also of the opinion that the owners of Gassled have received reasonable profits on their investment. During 2011 and 2012 several oil companies including ExxonMobil, Total, Shell, Eni and Statoil divested their

ownership interests (Statoil retained a minor interest) to financial investors. The subsequent amendment to the Tariff Regulation triggered litigation by the investors who claimed that the amendment to the Tariff Regulation is invalid. The claimants stated that their total loss as a result of the amendment to the Tariff Regulation was about 34 billion NOK. The State prevailed in the first instance. The judgment was appealed by the claimants.

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Overview of the legal and regulatory framework in Norway

A. ElectricityA.1 Industry structure

Norway’s domestic electricity production is based almost entirely on hydropower, accounting for approximately 96% of the energy mix. Under Act no. 16 of 14 December 1917, relating to acquisition of waterfalls, mines and other real estate (“Norwegian Industry Concession Act”), only public undertakings may acquire concessions for the ownership of hydropower resources.1 Public undertakings are defined as undertakings where the Norwegian public sector directly or indirectly control at least two thirds of the shares and the capital, and which are organised in such a manner that genuine public ownership exists.2 Consequently, in Norway, large and medium scale hydropower must be publicly owned. This has been the case since the first developments in the electricity sector at the start of the last century. With regards to electricity production from other energy sources, such as wind power, the same ownership restrictions are not applicable.

The largest Norwegian electricity producer is Statkraft SF3 ("Statkraft") which is a fully state-owned enterprise. Statkraft owns approximately 36% of the Norwegian electricity generating capacity. A large number of local municipalities and county authorities own approximately 52% of the generating capacity, mostly exercised through ownership interests in public undertakings. Private companies4 still own roughly 12% of the generating capacity on the basis of previous concession legislation.5

Unlike most other European countries, Norway has three grid levels rather than two: the central grid; the regional grid; and the local distribution grid. The central grid, which for most practical purposes is the Norwegian transmission grid, is operated by the wholly state-owned enterprise Statnett SF ("Statnett"). Statnett is designated as the TSO with particular system responsibility pursuant to the Norwegian Energy Act (the "Energy Act").6 Statnett owns around 87% of the central grid and operates the remaining parts of the central grid on the basis of rental agreements.

The state's interest in Statnett is held by the Ministry of Petroleum and Energy ("MPE") whereas the state's interest in Statkraft is held by the Ministry of Trade and Energy. Consequently the structure of public ownership in Statnett and Statkraft complied from the outset with the full ownership unbundling requirements of the Third Electricity Directive. This position was made clear in Article 9(6) of the Third Electricity Directive, which states that two separate public bodies are not deemed to be the same entity.

The regional and distribution grids are owned by a large number of companies, mostly owned, in turn, by county and municipal authorities. Privately owned companies are more common within electricity trading than other areas of the industry, although there are private companies in all parts of the resource chain.

Regulatory responsibility and supervision within the electricity sector is, to a large extent, delegated from the MPE to the national regulatory authority, the Norwegian Water Resources and Energy Directorate ("NVE"). This includes activities such as granting concessions, in the first instance, for the building and operation of electricity production plants7 and grid infrastructure, and the setting of overall grid tariff levels ("Income Frames").

The Energy Act represents the backbone of Norwegian electricity market regulation, covering all parts of the resource chain from electricity production to consumption.8 With the adoption of the Energy Act in 1990, full competition was (at least in principle) introduced in the Norwegian electricity sector, with effect from 1 January 1991. This regime has been developed into a Nordic competitive electricity market, which can be characterised today as an advanced regulatory market model which functions effectively.

The Energy Act is a framework act which, inter alia, sets out the following:

•• the general concession requirements for local area licences for the construction of distribution grids;

•• construction and operating licences for other installations, including power stations and transmission grids;

•• trading licences applicable to monopoly grid operators as well as electricity producers and traders, marketplace licences, and import and export licences.

The key group of licences are the trading licences which provide, inter alia, the power to govern grid company operations and tariffs as further set out in the regulations which accompany the Energy Act.9 As from 1 July 2013, import and export licences are only granted to the projects where the TSO (Statnett) has a controlling interest.

The Norwegian electricity market regime generally complies with the provisions of the Third Electricity Directive, which is deemed EEA relevant by the Norwegian Government. Amendments have been made in the energy legislation to reflect the requirements of the Third Energy Package with respect to a.o. ownership unbundling and the roles of the transmission system operator. Further amendments may still be necessary, in particular in relation to the Third Electricity

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Directive’s comprehensive new set of provisions governing national regulatory authorities. These regulatory changes have been made regardless of the fact that the EEA Committee has yet to decide whether the Third Electricity Directive can be deemed relevant to the EEA, and the directive has not yet been incorporated into the EEA Agreement.

A.2 Third party access regime

Regional grid and distribution grid companies operate the grid pursuant to a trading licence.10 The objective of this licensing regime is to facilitate an efficient electricity market and effective operation, utilisation and development of the grid.11 The licence requirements for grid operators include conditions concerning, inter alia, organisation, non-discriminatory market access, impartial behaviour, and the calculation of tariffs.12 In this respect, licensees must ensure market access for all customers who want grid services at non-discriminatory and objective point tariffs and terms.13

Distribution grid companies with local area licences are at the outset required to ensure that customers within their grid area are supplied with electricity from their grid.14 Grid companies are also required, if necessary, to invest in new grids in order to connect to new production or supply facilities.15 Grid companies may be exempted from the investment obligation in electricity production facilities if the grid investment is not considered to be socio-economically efficient, while an exemption from the investment obligation in new supply will only be granted in extraordinary cases. On the production side, the investment obligation is likely to be of greatest practical significance for new small-scale renewable production facilities where project financing of a separate production grid may be difficult to obtain.

A.3 Market design

The Norwegian electricity sector is characterised by a liberalised end-consumer market, a very advanced wholesale market, a detailed regulation of natural monopolies such as grid services and tariff levels (point to point tariffs and regulator set income frames), a strict licensing regime for activities such as construction, ownership, operation, trading etc. There are no feed-in tariffs or capacity markets (apart from the balancing power market which provides an operating reserve capacity).

There is a strong focus on security of supply, efficient production of renewables, integration with European energy markets, and a more efficient and climate-friendly use of energy.

These instruments and objectives are laid down in the Energy Act and its pertaining regulations. In addition, the Planning and Building Act, the Greenhouse Gas Emissions Trading Act and the El-Certificate Act, as well as the different support schemes, all play important roles in the Norwegian energy policy which drives the market design.

A.4 Tariff regulation

Grid tariffs are set by the grid operators on the basis of yearly Income Frames determined by the regulator, NVE. The overall principles for the determination of Income Frames are that the grid revenues, over a period of time, will cover the costs of operation and depreciation of the grid while giving a reasonable rate of return on invested capital assuming efficient operation, utilisation and development of the grid.16

The stipulation of point tariffs for individual customers (ie, tariffs referring to the customer’s connection point to the grid that are independent of power purchase and/or sales agreements) must be non-discriminatory and objective.17 Further requirements to this effect are provided in part five of the Control Regulation.

A.5 Market entry

Licences are required for construction, ownership and operation of power producing facilities, as well as for trading and transportation of electricity. Subsequent to the entry into force of the amendment to the Energy Act that repealled the provision that granted Statnett a monopoly to obtain licences to build and operate interconnectors, there are no particular legal or practical barriers for obtaining licences.

Section 3-1 of the Energy Act sets out the licence requirements for the construction, ownership or operation of electrical installations such as electricity generation and transmission facilities. Electricity distribution grids are in practice governed by a separate area licence requirement pursuant to section 3-2 of the Energy Act. The Planning and Building Act sets out requirements for construction projects, including impact assessment requirements including environmental impact assessments,18 as well as other requirements.

Ownership of hydropower resources over a certain potential capacity threshold (in practice large and medium scale hydropower production) is subject to specific restrictions pursuant to the Industry Concession Act (see section A.1 above). Consequently, foreign and private market participants cannot be granted such hydropower licences and may only participate in their capacity as minority shareholders in Norwegian public companies.

Trading licences must be obtained by companies trading electricity in their own name. The process for obtaining a trading licence for a trading company is standardised, and applications may be filed online to the regulator, NVE. As of 25 November 2016, approximately 460 companies held a trading licence in Norway, including producers, grid companies and trading companies as well as integrated companies performing several of the aforementioned services.19 Of these, approximately 165 are actively engaged in trading electricity. Companies must sign a standardised participant agreement in order to trade electricity on the Nord Pool Spot.20

A.6 Public service obligations and smart metering

No particular public service obligations apply to specific producers and suppliers in Norway (a possible exception being that the TSO, Statnett, may instruct market participants, typically larger producers, to provide regulating capacity at cost plus a reasonable rate of return). With respect to grid companies, Statnett is subject to a number of obligations in its role as TSO with system responsibility. DSOs are also subject to a number of obligations. The obligations of the TSO and DSOs to a large extent correspond to the tasks appointed to these grid operators under the Third Electricity Directive.

The regulatory requirement, which was introduced in July 2011, stipulates that the grid companies shall install advanced metering systems at all measuring points within their licensing area by 1 January 2019.21 The regulation assumes a gradual

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approach, whereby the grid companies as from 1 January 2015 on a regular basis report periodically on the progress of installation of smart metering systems to NVE. By the end of 2016, close to 500 000 householdings have installed smart metering, and by the end of 2017 it is expected that installation will be completed for approximately 70% of all electricity customers. The total number of smart meters to installed is around 2.7 million.

A.7 Cross-border interconnectors

Cross-border interconnector capacity from Southern Norway today amounts to a total of 3,700MW (under normal conditions), including 2,050MW capacity to Sweden, 950MW to Denmark and 700MW to the Netherlands (the NorNed cable). Interconnector capacity in mid and Northern Norway includes another 1,400 to 1,700MW to Sweden, 120MW to Finland and 50MW to Russia.22 A 700MW cable to Denmark (Skagerrak 4) is under construction, and is planned to be operational in 2014. Planned new projects include a new 1,400MW cable to Sweden (Sydvestlinken), which was notified to the NVE in October 2011 and is planned to be operational by 2020, as well as two new cables to Germany and the UK, called Nord.link/NorGer and NSN, respectively. These are planned to be operational in 2018 and 2021.23 In total, the new planned cross-border transmission capacity is 4,000MW in the coming 10 years.

As mentioned above, the Norwegian Parliament decided on 25 October 2016 to repeal the provision in the Energy Act such that Statnett shall no longer be the only entityallowed to hold licences for cross-border interconnectors.

B. Oil & GasB.1 Industry sturcture

Norway is a gas exporter; only small quantities of gas are transported onshore for domestic use. Crude oil is partly refined in Norway and partly exported abroad. For a description of the Norwegian upstream licensing regime, an overview of key market players, the national regulatory authority, key legislative, regulatory and contractual features etc., please refer to section F below.

The Norwegian domestic downstream gas market has not yet matured and is considered an emergent market for the purposes of the Second Gas Directive. Unbundling in the downstream gas market has not yet been considered a pressing issue in Norway. The Third Gas Directive which at the time of writing is not yet included in the EEA agreement and incorporated under Norwegian law, will most likely not alter this.

B.2 Third party access regime to gas transportation networks

Access to the Norwegian upstream pipeline system is regulated by the MPE, through the Petroleum Act24 and the Petroleum Regulation,25 which follow the principles of third party access laid down in the upstream pipeline system provision of the Second Gas Directive. The Third Gas Directive has not yet been implemented, but the MPE considers that it will not necessitate any changes to the current upstream regime.

Natural gas undertakings and eligible customers with a "duly substantiated reasonable need" (behørig begrunnet rimelig

behov) for transportation (shippers) are entitled to access the system on objective and non-discriminatory conditions.

It is the responsibility of Gassco as the system operator to operate the access regime, which consists of a primary and a secondary market. In the primary market the shippers reserve capacity through Gassco. If the requested reservations are higher than the spare capacity, the right to use the spare capacity is allocated according to an allocation formula.

In the secondary market, natural gas undertakings and eligible customers may transfer their reserved capacity to other natural gas undertakings and eligible customers with a duly substantiated reasonable need for transportation, either through the market place organised by Gassco or by bilateral agreements.

Onshore gas distribution in Norway is limited to a small distribution network, which is linked to the Kårstø gas processing facility on the Norwegian West Coast. Gas distribution is regulated by the Natural Gas Act26 and pertaining regulations. There is currently no particular legislative framework addressing transportation tariffs in the Norwegian downstream gas market.

B.3 LNG terminals and storage facilities

In Norway, domestic gas consumption is limited, and there are only a few small scale facilities for receiving LNG, located on the Norwegian West Coast. The Snøhvit LNG facility, located in Hammerfest in Northern Norway, is a full scale facility for the export of LNG, processing gas from the Snøhvit field in the Barents Sea.

Upstream LNG facilities also fall within the Petroleum Act and follow the same regulatory regime as other petroleum activities. Downstream LNG facilities are governed by the Natural Gas Act, and are subject to less detailed regulation and no general third party obligations (although such access may be stipulated by the government on a case-by-case basis).

There is no onshore gas storage in Norway, except some storage facilities at the Kårstø gas processing facility.

B.4 Tariff regulation

The transportation (and/or processing) of natural gas within the Gassled upstream transportation system is regulated by a standard agreement entered into between Gassco (on behalf of Gassled) and the shipper. The tariff is regulated in a separate Tariff Regulation27 and is payable on a ship-or-pay basis. The tariffs consist of a capital and an operating element,28 and the transportation system is divided into different zones, with separate tariffs applying to each zone.

B.5 Market entry

In order for a company to be eligible for the award of a production licence, it must be pre-qualified as a licensee, meaning that the company must fulfil certain criteria such as its qualification or financial strength. In practice it is required that the licensee is incorporated and registered in Norway. While the award of licences is subject to the principles set forth in the Licensing Directive,29 the authorities will, when considering whether a pre-qualified company will be awarded production licence(s), take into account the particular features of the application in

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question, such as the applicant’s proposed work obligations. The final award is subject to negotiations with the authorities.

B.6 Cross-border interconnectors

The Norwegian natural gas transportation system is complex, with several interconnections and export pipelines. Currently, there are seven major pipelines transporting natural gas from the NCS to the UK and continental Europe; the Vesterled pipeline, the Langeled pipeline, the Franpipe pipeline, the Zeepipe pipeline, the Norpipe pipeline, and the Europipe I and II pipelines. Norwegian gas is also transported to the UK through the British Flags pipeline. All of these pipelines are comprised by the Gassled upstream transportation system. Please refer to B.2 and B.4 for a description of access regime and tariffs.

C. Energy tradingC.1 Electricity trading

Electricity can be traded bilaterally or on the regulated market places Nord Pool Spot or NASDAQ OMX Oslo AS. The Nordic power exchange, Nord Pool Spot,30 offers physical trading with both day-ahead ("Elspot") and intra-day ("Elbas") markets. Gate closure for day-ahead trades on the Elspot market is 12pm.31 In order to participate in Nord Pool Spot’s physical markets, participants must, inter alia, sign a participant agreement which also applies Nord Pool Spot’s trading rules.32

Market participants are required to achieve a balance between commitments and rights for each hour in each Elspot area.33 Several instruments are available to achieve such hourly balance. The Elbas market opens up for hourly trade and consequently also provides a balancing market. In addition, the Norwegian TSO Statnett administers a regulating power market (where market participants bid for regulating power) and a regulating power options market for balancing purposes. In the latter options market, which is operated on a weekly basis, participants may commit to future bids in the regulating power market for a fee paid by Statnett.

Financial trading is organised by the power derivative exchange NASDAQ OMX Oslo ASA (formerly known as Nord Pool ASA). Through the brand name NASDAQ OMX Commodities, the financial power trading exchange provides trading and clearing services for power derivatives (and carbon contracts), thus providing price hedging possibilities for participants also engaged in physical trade, as well as trading opportunities for participants solely engaged in financial transactions.34 Contract terms of up to 6 years are offered.

C.2 Gas trading

Gas produced on the NCS is the property of the respective licensees, who are obligated to market, transport and sell their gas; the exception being that the equity gas of the State’s Direct Financial Interest ("SDFI") is marketed and sold by Statoil together with its own equity gas. Gas sales are carried out by the individual licensees on a bilateral basis.

Trading is primarily carried out on a physical basis and there is very little financial trading in natural gas in Norway. Although gas volumes are increasingly being sold on short term contracts, most Norwegian natural gas is still sold on long term take-or-pay contracts to the UK and continental buyers,

typically with durations of 20 years or more. Most of the long term contracts are traditionally based on price formulas which are linked to the price of alternative sources of energy. However, there has been a transition to the use of more gas indices in long term contracts as well. Short term contracts are typically entered into on the basis of market standards such as the NBP, ZBT and EFET contracts.

Licensees are required to report to the authorities, on a quarterly basis, information regarding their gas delivery obligations, including information on volume profiles and main contractual terms.

As there is no gas hub trading taking place in Norway there is no downstream balancing regime as such. In the upstream sector, Gassco is responsible for balancing the inlet and outlet of natural gas and maintaining necessary pressure in the Gassled transportation system.

In order to use the upstream transportation system, shippers need to reserve capacity with Gassco. Apart from providing the volume information as required pursuant to the access regime (see section B.2 above), no particular notification requirements apply with regard to contractual volumes.

D. Climate change and sustainability D.1 Climate change

The Norwegian climate policy is built on the 2008 and 2012 agreements on climate policy, in which the political parties in Norway agreed for Norway to be carbon neutral by 2050. The government wants the Norwegian energy supply to be the basis for continued growth and welfare, focusing on enhanced security for supply, efficient production of renewables, more efficient and climate friendly use of energy and economic growth and value creation through efficient use of profitable use of energy sources.35

Further, the Paris Agreement and the UN targets for sustainability are both influencing the Norwegian efforts and policies for the climate and environment. A number of important measures have been taken as part of these agreements. One of the more recent ones, took place in the first half of June 2016 when the majority of the political parties in the Parliament decided upon a much more ambitious target and pushing the target for carbon neutrality forward to 2030.36 This came just weeks prior to the formal ratification of the Paris Agreement on 21 June 2016, followed up by an agreement with the EU to collaborate in order to meet the targets set in the Paris Agreement. Norway is now aiming for a 40% reduction in emissions by 2030 compared to the baseline year 1990, and will have to operate with an emission budget, annually reporting to the EU and with a settlement of the emission accounts every five years. All of these activities are done in parallel with the on-going work to implement a new Climate Act, which is intended to legislate the emission reduction targets and make the Government accountable. The proposed Climate Change Act was out on public hearing in the period September-December 2016, and is expected to be sanctioned in 2017. The proposed National State Budget for Norway 2017 had climate change as an important topic, and it is recognised that Norway cannot reach its targets without proper funding.37

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D.2 Emission trading

The emission trading scheme is regulated by the Greenhouse Gas Emission Trading Act. This Act introduced a quota system for carbon dioxide emissions which has been effective since 1 January 200538 The authorities then allocated a certain number of free tradable allowances for carbon dioxide emissions among certain entities in the business sectors subject to the quota system.

Norway did not implement the earlier emission trading directive (2003/87/EC) in the 2005 to 2007 period, but as of January 2008 the Norwegian emissions trading system was merged with the EU scheme, allowing Norwegian businesses to trade allowances within the EU. The New EU ETS Directive was incorporated into the EEA agreement in July 2012, and the allowance award rules are identical to the EU rules. Norwegian businesses may trade and surrender both European Union Allowances and Certified Emission Reductions issued directly by the Norwegian authorities in addition to allowances when fulfilling their obligations under the aforementioned Act.

Being a part of the EEA, Norway will further have to adapt to any changes in the EU ETS, and currently the EU ETS is undergoing a reform as a result of the Energy Union strategy adopted in 2015. The reform aims at a significant decrease in emission caps and a gradual increase in the carbon price. In addition, they are aiming at establishing an Innovation Fund, NER400, to replace NER300. The Innovation Fund shall fund innovative renewable energy, CCS and projects aiming at decarbonising industrial production.39 The Innovation Fund will be an additional measure to the Market Stability Reserve as was agreed on in 2015, which intends to adjust the number of allowances to be auctioned in order to address the current surplus on the carbon market and make the system more resilient to changes in demand.40

D.3 Carbon capture and storage

As part of the EEA, Norway is obligated to implement the EU regulatory framework for carbon capture and storage ("CCS"), as reflected in the EU Storage Directive.41 This implementation was finalised on 5 December 2014, through the Regulations on Transport and Storage of CO2 on the Continental Shelf ("Storage Regulations"),42 a new chapter 4a to the Petroleum Regulations ("PR")43 and a new chapter 35 to the Pollution Control Regulations ("PCR").44

In general all CCS activities in relation to petroleum activities, like CO2-EOR (separation and storage of CO2 while extracting, for example. natural gas for processing and sales), will be regulated by the Petroleum Act ("PA")45 and the PR in combination with the requirements under the PCR, meaning that the storage permit is subject to approval under both the PR and the PCR. CCS activities initiated in relation to other industrial activities, or industrial CCS, are regulated by the Storage Regulations in combination with the PCR, implying that the permit is subject to approval under both the Storage Regulations and the PCR. The permitting regime was further refined in March 2016, by the release of Guidelines on the Financial Security and Financial Mechanism for CO2 Storage,46 given subject to the PCR Section 35-15 and the Storage Directive’s non-binding guidelines for financial security and financial mechanisms.

Norway has a long history demonstrating the secure storage of CO2 in the offshore environment. In 2016, Statoil celebrated the 20 year anniversary of CO2 injection at the Sleipner CO2 Storage Project. In this period, more than 16 million tonnes of CO2 have been securely stored beneath the seabed. In 2008, Statoil further launched the Snøhvit CO2 Storage Project, which since then has injected more than three million tonnes of CO2.These two projects have been the only active CCS projects in Europe since commissioning, and were initiated party due to the need to strip the natural gas for CO2 prior to selling it in the European market and partly due to a CO2 tax that was implemented in 1990.47 In early August 2016, Statoil submitted a Plan for Development and Operation ("PDO") and a Field Development Plan ("FDP") for the Utgard Field, in which they plan to transport gas and condensate it through a new pipeline to the Sleipner field for processing and use the carbon capture facilities at Sleipner to separate the CO2 and re-inject it in the Sleipner Field prior to further transportation to the market.48

In addition to the activities mentioned above, the Norwegian Government has initiated and participated in a number of activities, through the state-owned company Gassnova SF. One of their most successful projects is the CO2 Technology Mongstad ("TCM"), the world’s largest test facility for CO2 capture technology, which has been built and operated in collaboration with Statoil ASA, A/S Norske Shell and South African energy company Sasol. TCM was opened for operation in 2012, with an initial period of operation for five years. This period has been extended for another three years.49

Following the cancellation of the full-scale CCS project Carbon Capture Mongstad in 2013,50 the Norwegian Government published a new CCS strategy in 2014, which comprised the three pillars of research, demonstration and testing of technology and broad scale utilisation of CCS.51 In addition to the renewed efforts on TCM, this meant a continuance of CLIMIT, which is Norway’s national programme for research and development of CCS, as well as the initiation of a new project aiming at a full-scale CCS demonstration. Phase one of this project, the pre-feasibility study, was finalised in June 2015. The studies focused on three different emission sources; Norcem AS assessed the possibility for capturing CO2 from the flue gas at its cement factory in Brevik, Yara Norge AS assessed CO2 capture from three different emissions points at its ammonia plant at Herøya in Porsgrunn and the Waste-to-Energy Agency in Oslo municipality assessed CO2 capture from the waste recovery plant at Klemetsrud (Klemetsrudanlegget AS). In addition, Gassco studied alternative solutions for transportation and Statoil studied storage sites offshore. The following phase, feasibility studies, was finalised in June 2016. The conclusion was that it would be feasible to realise a full-scale project on all of the three emission sources, and preferable solutions for transport and storage were selected and put forward as recommendations for the Government.52

The proposed Norwegian budget for 2017 allocated over one billion Norwegian Kroner to CCS, including funding for FEED studies, for a full-chain CCS project with all the three emission sources with transport and storage options, renewed efforts for TCM as well as further funding for research and development through the CLIMIT programme. Furthermore, the Government emphasised its ambitions of commissioning at least one full-scale CCS demonstration project by 2022, adjusted from

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the previous ambitions to realise the project by 2020 due to the recommendations put forward in the feasibility studies.53

D.4 Renewable energy

The Renewable Energy Directive is EEA relevant and was incorporated into the EEA agreement in December 2011 and made applicable to Norway. While almost all electricity production in Norway is currently based on renewable energy sources, the extended scope of the Renewable Energy Directive (compared to Directive 2001/77/EC) to include other categories of energy production holds challenges for Norway in meeting its target of increasing the total share of gross domestic energy consumption originating from renewables to 67.5% by 2020 from approximately 60%. The Norwegian government submitted its action plan for meeting this target just before summer 2012. It is foreseen that energy efficiency measures will play a major role, as will electrification of the transportation sector (where there has already been a huge increase in the presence of electric cars), decreased use of fossil fuels for heating, and a decrease in total energy consumption. In addition, Norway has large potential with regard to the development of electricity production from renewables. Wind power in particular has a lot of potential. Existing hydropower facilities are also being upgraded, and investment in new small scale hydropower generation is taking place. Norway and Sweden have a common system with green certificates, and have a combined goal of establishing 26.4TWh of new electricity production based on renewable energy by 2020. Norway and Sweden are each responsible for financing 13.2TWh in the certificate system, regardless of the amount of production that is located in each of the two countries.

The electricity certificate system is a market based support scheme to promote new electricity production based on renewable energy sources. Producers will receive one certificate per MWh of renewable electricity that is generated for a period of 15 years. Electricity suppliers and certain consumers have a statutory duty to buy electricity certificates. Norway and Sweden have a common system with green certificates in place.

Despite the electricity certificate support scheme, investments in wind power remained low. In order to increase the attractiveness of investments in wind power, Norway introduced more favourable tax incentives for this sector. The new regime included a 5 year linear depreciation of production factors in wind power stations. This amendment will lead to more profitable early stages of development for new hydro power stations. The new depreciation rules are limited to investments made from 19 June 2015 and until 31 December 2021. In 2016 the EFTA Surveillance Authority ("ESA") approved this tax regime to be compliant with EU state aid legislation.

Furthermore, as part of the path towards reaching the national target, NVE has significantly improved its case handling capacity and efficiency, which in 2012 resulted in concessions encompassing almost twice the generating capacity compared to the same in 2011.

As mentioned above, in order to increase the possibility for investments in interconnector projects, both to ensure Norway’s needs in terms of security of supply and in order to export renewable energy, the Parliament decided on 25 October 2016 to amend the Energy Act in order to allow entities other than the TSO to own and operate interconnectors from the Norway. However, the new provision has not entered into force yet.

D.5 Biofuel

The Biofuel Directive is considered EEA relevant and is incorporated in Norwegian law under the Norwegian Product Regulation, as per the amended Directives 98/70/EC and 99/32/EC. Chapter 3 of the Product Regulations includes blending requirements for biofuel, requirements with regard to the sustainable cultivation of the raw material used, requirements that production and use of biofuel must lead to reduced emissions of greenhouse gases compared to fossil fuels and sustainability criteria for biofuels and liquid biofuels.

An amendment has been made to chapter 3 of the Product Regulation regarding supply of biofuel in connection with road transportation. This amendment will enter into force on 1 January 2017. The amendment was made as a result of a Parliamentary budget decision to ensure compliance with the EU sustainability criteria in order to increase use of biofuel in Norway. This amendment requires that a minimum share of 7 per cent of the total supply of fuel for road transportation shall be from biofuel, except biogas. There is also a requirement that a minimum of 1.5 per cent of all biofuels used in road transportation shall be produced from wastes, residues, non-food cellulosic material and ligno-cellulosic material and that such fuels will be considered twice when calculating the blending requirements under the regulations. Moreover, the amendment clearly set out an obligation to reduce greenhouse gas emissions from road transportation by use of biofuels to between 35 and 50 per cent in the coming years.

The ILUC Directive (2015/1513) on the quality of petro fuels and promotion of use of energy from renewable sources is currently being considered by the EEA Committee in order to evaluate the EEA relevance for the EEA countries. If the ILUC Directive is regarded as relevant by the EEA Committee it will have to be implemented into Norwegian law.

Certain biofuels such as biogas, hydrogen, hythane and electricity used in electric cars and hybrid cars, are exempt from the duty of payment relating to the Norwegian Road Use Charge. This exemption will promote use of such renewable types of fuels.

E. Nuclear energyThere is no nuclear energy production in Norway.

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F. UpstreamThe ultimate authority for the regulation of petroleum activities on the NCS lies with the Norwegian Parliament (Stortinget). The overall responsibility for ensuring that the petroleum activities are carried out in accordance with the regulatory framework rests with the MPE. Below the MPE there are two entities, the Norwegian Petroleum Directorate (the "NPD") and the Petroleum Safety Authority (the "PSA").54 Policy and legislation concerning petroleum taxation is handled by the Ministry of Finance (the "MoF") and annual tax assessments are carried out by the Oil Taxation Office.

The legal basis for government regulation of the petroleum sector is found in the Petroleum Act which provides the legal framework for the licensing system. The legal basis for taxation of offshore petroleum activities is the 1975 Act relating to Taxation of Subsea Petroleum Deposits.55

In addition to the high level provisions in the Petroleum Act, offshore petroleum activities in Norway are subject to a very comprehensive system of regulations and approvals, including the Petroleum Regulation, which mainly addresses resource management, and the HSE Regulations56 which address the health, safety and environmental aspects of the activities. As a general approach, the HSE Regulations are function-based and risk-based, leaving it up to the oil companies to choose how to fulfil the requirements. The Norwegian system also implies a "see-to" duty (påse-plikt) on the licensees. This means that the oil companies have a duty to ensure that all of its contractors and subcontractors comply with applicable regulations. The non-operators also have a "see-to" duty towards the operator.

The level of state participation in the Norwegian oil and gas industry is high. The Norwegian state is the largest player on the NCS, by way of its shareholdings in Statoil ASA, and through the SDFI, whereby the state participates directly in various production licences.57

The Norwegian offshore licensing system comprises various licences, approvals, agreements and other mechanisms.

The production licence is the core document in the licensing system, and gives the licensee an exclusive right to explore for, develop and produce petroleum in the block(s) covered by the licence. Production licences are normally awarded through annual licensing rounds. In addition, all unlicensed acreage in the mature North Sea area is open for application in annual award procedures, a process known as awards in predefined areas ("APA"). Companies can apply for licence awards individually or in groups.

The production licence can be awarded to one or several oil companies. To become licensees, companies must fulfil certain criteria regarding technical qualifications, organisational requirements, financial strength, and others. The MPE offers a pre-qualification procedure which outlines these criteria in order to facilitate the application preparations of prospective licensees. The same criteria will apply to a prospective assignee of a production licence interest or the shares in a company holding licence interests. Transfer of a licence interest and transfer of shares in a company holding a licence interest is subject to approval by the MPE and MoF.58

The company appointed as operator by the MPE becomes responsible for executing the day to day management of the petroleum activities on behalf of the licensees. In addition to fulfilling the general requirements for all licensees, the operator must have the additional capabilities necessary to carry out the day to day activities of the licence group. No particular corporate structure requirements apply, although in practice most licensees are set up as Norwegian limited companies. The qualifications of the operator will in practice vary with the developing stages of the licence, and stricter requirements will apply for operating a licence in the production phase than in the exploration phase. Transfer of operatorship is subject to government approval, and the same requirements will apply to the prospective new operator.

The production licence is awarded for an initial period (which may be up to 10 years). Within this period, a specified work obligation must be fulfilled – this is often an obligation to procure seismic data and to drill an exploration well. After such fulfilment, the duration of the licence is normally extended. An area fee also applies after the initial period, based on the size of the licence acreage. If the work obligation is not fulfilled within the stated time limit, the licence will generally be revoked. A licence can also be withdrawn as a result of serious or repeated violations of the Petroleum Act such as those pertaining to regulations or licence conditions.

If a licensee wants to grant security over a production licence interest to finance its activities associated with the licence, the consent of the MPE is required, which is regularly given. The MPE can also, 'in special cases', consent to allow the financing to include activities pursuant to a licence other than the one which is mortgaged. While the possibility for extending the purpose of financing was originally meant to be limited, such consent has in practice been granted quite often.

One of the conditions of the award of the production licence is that the licensees enter into a joint operating agreement (the "JOA") in a standard format prepared by the MPE. The JOA governs the relationship between the licensees, forming the basis for day to day management of the activities, allocation of costs, decision making processes, and other processes. All petroleum produced is allocated to the licensees in accordance with their participating interest.

In order to develop a petroleum discovery, the licence partners must submit a plan for development and operation ("PDO") to the authorities. The PDO sets out, inter alia, the development solution, estimated development costs and a production profile for the deposit.59

Based on the PDO, the NPD issues annual production permits which allow the licensees to produce defined volumes of petroleum. The export of petroleum is not subject to a specific legal regime as such.

The licensees are also required to submit a plan for decommissioning and cessation of the petroleum activities to the MPE. The MPE then decides, based on the plan, on the disposal of the facilities. In relation to the transfer of the production licence interest, the transferor will remain liable to the remaining licensees for the share of the decommissioning costs associated with the transferred licence interest. This requirement, which was

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introduced in 2009, has in practice affected the market for licence share transactions, as assignors will regularly demand additional security from the assignee in order to be held harmless for such potential secondary liability. Contractually, this is usually structured around a decommissioning security agreement, which is appended to the sale and purchase agreement.

Construction and operation of transportation and/or processing facilities is subject to a plan for installation and operation ("PIO"), which must be submitted to the MPE for approval.60

The Norwegian offshore gas transportation infrastructure system ("Gassled") is organised as one joint venture. Historically, Gassled has been owned by the main shippers of natural gas from the NCS. However, ExxonMobil, Total, Norske Shell and Statoil have sold their ownership interests to financial investors (but with Statoil retaining a 5% ownership interest). Standard provisions apply for access to the Gassled facilities (see section B.2 above). The Gassled system is operated by Gassco, a fully state owned company which is not a shareholder in Gassled. Gassco exercises its operator duties as an independent system operator ("ISO"), pursuant to the provisions of the Petroleum Act and in accordance with an operator agreement with Gassled.

For companies engaged in oil and gas operations on the NCS, there are two, partially overlapping income tax regimes: ordinary income tax imposed by the general rules in the Norwegian General Tax Act of 1999 ("GTA"), and the special petroleum tax on income imposed by the Petroleum Tax Act ("PTA"). As a result, the total marginal income tax rate for companies engaged in exploration and production activities on the NCS is 78%, consisting of a 27% general income tax and a 51% special petroleum tax to the state. These rates were changed in 2013, with effect from 1 January 2014, from 28% general income tax and 50% special petroleum tax. The marginal income tax is thus the same.

Gross income generated by oil sales is assessed according to a norm price system, where sales prices are fixed by an administrative body, whereas income generated by gas sales is assessed on actual sale prices. A licensee on the NCS that is subject to Norwegian taxation will be entitled to tax deductions against income taxed at 78% with regard to exploration and production costs (running expenses, net financial items, depreciations and uplift) and transportation costs (tariff payments). Production installations depreciate over six years, and an uplift is granted on a special tax basis for a four year period for investments in production and pipeline facilities. The uplift was changed from 7.5% to 5.5% per year by law in 2013, with effect from 5 May 2013.61

An exploration refund scheme was introduced in 2005, whereby companies not entitled to deductions may annually claim a refund from the state of the tax value of direct and indirect costs. This is with the exception of financial charges, incurred in exploration for petroleum resources.62 The tax value is currently 78%. The refund will reduce in correspondence with the tax loss carried forward.

Endnotes1. Other than small scale hydropower.2. Norwegian Industry Concession Act, see in particular sections 1 and 2. 3. Formally its fully owned subsidiary Statkraft Energi AS.4. Although with some minority public shareholding.5. See further The Norwegian Ministry of Petroleum and Energy, Facts 2008 – Energy and Water Resources in Norway, pp. 78 et seq. for an overview of ownership shares

[www.regjeringen.no/en/dep/oed/Documents-and-publications/Reports/2008/fact-2008---energy-and-water-resources-i.html?id=536186] (url last visited on 14 September 2010).

6. Act 29 June 1990 No. 50, section 6(1). See also the appurtenant Regulation 7 May 2002 No. 448 concerning system responsibility in the power system.7. This does not include licences for acquisition of hydropower resources pursuant to the Norwegian Industry Concession Act.

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8. See section 1(1) of the Act.9. The more specific provisions relating to market operation follow from regulations to the Energy Act, including the Energy Regulations of 7 December 1990 No 959, which

is a Royal Degree, and subordinate regulations such as the Control Regulation of 11 March 1999 No 302 and the Electricity Supply and Grid Services Regulation of 11 March 1999 No 301. Other important regulatory instruments relevant to the electricity market include the Industry Concession Act of 14 December 1917 No 16 and the Watercourse Regulation Act of 14 December 1917 No 17 (both for hydropower development), the Planning and Building Act of 27 June 2008 No 71 and the Competition Act of 5 March 2004 No 12).

10. Awarded under Section 4-1 of the Energy Act.11. Section 4-1 of the Energy Regulation.12. Section 4-1 of the Energy Act and Chapter 4 of the Energy Regulation.13. Section 4-1(2)(2) of the Energy Act and section 4-4(d) of the Energy Regulation.14. Section 3-3 of the Energy Act.15. Section 3-4 of the Energy Act.16. Section 4-4(b) of the Energy Regulation. More detailed provisions on how to achieve this result are given in the appurtenant Control Regulation.17. Section 4-1(2)(2) of the Energy Act and section 4-4(d) of the Energy Regulation.18. Act 27 June 2008 No. 71. See also section 2-1 of the Energy Act.19. The Norwegian Ministry of Petroleum and Energy, Facts 2008 – Energy and Water Resources in Norway, p. 76.20. See section A.2 above.21. Regulation 3 November 1999 No. 301, , ref chapter 4 concerning advanced measuring and control systems.22. See Statnett, Netutviklingsplan 2011, p. 80, available at [http://www.statnett.no/Documents/Kraftsystemet/Nettutviklingsplaner/Nettutviklingsplan%202011.pdf.] (last

visited 25 October 2013). 23. See further ibid, pp. 11.24. Act 29 November 1996 No. 72.25. Regulation 27 June 1997 No. 653.26. Act 28 June 2002 No. 61.27. Regulation 20 December 2002 No. 1724.28. The capital element is stipulated by the MPE and will give the investors about 7% interest on the invested capital before tax. The operating element is cost based and laid

down by the operator.29. Directive 94/22/EC.30. Owned by the Nordic TSOs.31. The power exchange had a turnover of 310TWh in 2010 (including the auction volume in the UK market N2EX for energy contracts), and approximately 74 % of the total

electricity consumption in the Nordic countries was traded on Nord Pool Spot, see further Nord Pool Spot’s web pages [www.nordpoolspot.com/About-us/] with further presentations (last visited 3 October 2011).

32. Documents are available on [www.nordpoolspot.com/TAS/Day-ahead-market-Elspot/Rulebook-for-the-Physical-Markets/] (last visited 3 October 2011). 33. Section 8 of the System Responsibility Regulation.34. See further NASDAQ OMX Commodities’ web pages [www.nasdaqomxcommodities.com/].35. Meld. St. 25 (2015-2016), the White Paper Power for Change.36. C.f. Innst. 407 S (2015-2016).37. C.f. Prop. 1 S (2016-2017).38. Act 17 December 2004 No. 99.39. http://ner400.com/ , https://ec.europa.eu/clima/policies/ets/revision/index_en.htm.40. https://ec.europa.eu/clima/policies/ets/reform/index_en.htm.41. Directive 2009/31/EC of the European Parliament and of the Council of 23 April 2009 on the geological storage of carbon dioxide and amending Council Directive

85/337/EEC, European Parliament and Council Directives 2000/60/EC, 2001/80/EC, 2004/35/EC, 2006/12/EC, 2008/1/EC and Regulation (EC) No 1013/2006.42. Full Norwegian name: Forskrift om utnyttelse av undersjøiske reservoarer på kontinentalsokkelen til lagring av CO₂ og om transport av CO₂ på kontinentalsokkelen.43. Full Norwegian name: Forskrift til lov om petroleumsvirksomhet.44. Full Norwegian name: Forskrift om begrensning av forurensning.45. Full Norwegian name: Lov om petroleumsvirksomhet.46. Full Norwegian name: Nærmere bestemmelser om finansiell sikkerhet for CO2-lagring. 47. C.f. Act 21 December 1990 no 72 relating to tax on discharge of CO2 in the petroleum activities on the continental shelf.48. http://www.statoil.com/en/NewsAndMedia/News/2016/Pages/09aug-utgard.aspx.49. http://www.tcmda.com/en/Press-center/News/2016/The-Norwegian-Governments-supports-TCM-operations-until-2020/.50. http://www.gassnova.no/en/ccs-projects/full-scale-mongstad.51. https://www.regjeringen.no/en/aktuelt/Strong-commitment-to-CCS/id2005662/.52. https://www.regjeringen.no/en/aktuelt/good-potential-for-succeeding-with-ccs-in-norway/id2506973/.53. http://www.gassnova.no/en/crucial-climate-commitment-in-the-2017-budget.54. The main functions of the NPD relate to resource management while the responsibilities of the PSA relate to issues regarding health, safety and environment.55. Act 13 June 1975 No. 35.56. The Framework Regulations (Regulation 12 February 2010 No 158), the Management Regulations (Regulation 29 April 2010 No 611), the Facilities Regulations

(Regulation 29 April 2010 No 634), the Activities Regulations (Regulation 29 April 2010 No 613), and the Technical and Operational Regulations (Regulation 29 April 2010 No 612)

57. The SDFI is managed by the state-owned company Petoro AS.58. The tax effects of a transaction are normally approved by default pursuant to Regulation 1 July 2009 no. 956.59. The PDO must be approved by the MPE, and must also be presented to Stortinget if the estimated investment is more than NOK 10 billion.60. A PIO is not required if the facilities are already covered by a PDO.61. Section 1 Act 21 June 2013 No. 66.62. PTA section 3(c)(5).

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AlbaniaKrenar K. Loloci+355 4 225 0736kl@lolocilaw.com

AustriaBernd Rajal+43 1 534 37 50203b.rajal@schoenherr.eu

BelarusNatalia Anoshka+375 17 236 47 11anoshka@peterkapartners.by

BelgiumLode Van Den Hende+32 2 518 1831lode.vandenhende@hsf.com

Bosnia and HerzegovinaStevan Dimitrijevic+387 51 962 600stevan.dimitrijevic@dimitrijevicpartners.com

Davorin Marinkovic+387 51 962 600davorin.marinkovic@dimitrijevicpartners.com

BulgariaStefana Tsekova+359 2 933 1073s.tsekova@schoenherr.eu

CroatiaPetra Santic+385 1 4576 494p.santic@schoenherr.eu

Bernd Rajal+43 1 534 37 50203b.rajal@schoenherr.eu

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DenmarkAnders Stubbe Arndal+45 38 77 43 05asa@kromannreumert.com

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Triin Frosch+372 640 7170triin.frosch@rln.ee

FinlandToni Siimes+358 20 506 6578toni.siimes@roschier.com

FranceChristophe Lefort+33 1 53 57 7400christophe.lefort@hsf.com

GermanySilke Goldberg+49 30 221510 419silke.goldberg@hsf.com

GreeceGus J. Papamichalopoulos+30 210 817 1500g.papamichalopoulos@kglawfirm.gr

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IsraelRenelle Joffe+972 3 610 3890renj@meitar.com

ItalyMonica Colombera+39 02 89 63 071mcolombera@legance.it

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Ruslanas Cerniauskas+370 5 250 0800ruslanas.cerniauskas@rln.lt

LuxembourgChristian Point+352 40 78 78 206christian.point@arendt.com

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PolandJerzy Baehr+48 61 855 32 20j.baehr@wkb.com.pl

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