(1)

By letter dated 7 January 2009, a complaint was filed against Narvik municipality (‘Narvik’) regarding the sale of Narvik’s entitlement to concession power to Narvik Energi AS (‘NEAS’). The letter was received and registered by the Authority on 14 January 2009 (2). By letter dated 16 July 2009 (3), the Authority requested additional information from the Norwegian authorities. By letter dated 2 October 2009 (4), the Norwegian authorities replied to the information request.

(2)

On 14 December 2011, the Authority initiated the procedure provided for in Article 1(2) of Part I of Protocol 3 to the Surveillance and Court Agreement by adopting Decision No 393/11/COL (‘Decision 393/11/COL’). By letter dated 23 February 2012 (5), the Norwegian authorities provided comments to the Decision.

(3)

On 26 April 2012, the Decision was published in the Official Journal of the European Union and in the EEA Supplement to it (6). By email of 25 May 2012 (7), the Authority received comments from an interested party. By email of 28 June 2012 (8), the Authority forwarded these to the Norwegian authorities. By letter dated 30 November 2012 (9), the Norwegian authorities submitted further information.

(4)

The complainant alleges that Narvik by entering into a contract with NEAS for the sale of 128 GWh of annual concession power for a period of 50,5 years, has sold its rights to buy the concession power significantly below the market price and thereby granted illegal state aid to NEAS.

(5)

The complainant further alleges that the decision to enter into the contract was adopted by Narvik Municipal Council on the basis of incorrect and/or incomplete information. Allegedly expert reports critical of the duration of the contract and the inherent difficulty in establishing a market price for electricity were not disclosed to the Municipal Council prior to taking the decision to enter into the contract.

(6)

In Norway, a concession is generally required for the operation of larger hydro power plants. The plants holding concessions for waterfall exploitation is obliged to sell a certain volume of their annual production to the municipality within which they are located. The volume of electricity that the municipality is entitled to purchase is referred to as concession power. This system is laid down in Section 2(12) of the Industrial Licensing Act (10) and Section 12(15) of the Waterfalls Regulation Act (11).

(7)

The legislative rationale is that the municipalities should be ensured a sufficient supply of electricity at a fair price, thus the volume of the concession power is determined on the basis of the general electric power supply needs of each individual municipality (12) and can be up to ten per cent of a plant’s annual production. There are, however, no restrictions imposed on the municipalities’ exploitation of concession power. Thus, the municipalities may use, sell or otherwise deploy it as they see fit.

(8)

The entitlement does not entail that the municipalities are under an obligation to buy concession power. For concessions pre-dating 1983, the caveat generally applies that once a municipality has decided not to exercise its right to concession power, it loses its right to concession power for the future.

(9)

The legislation sets out two pricing regimes for concession power; the first for concessions granted prior to 10 April 1959, the other for concessions granted on 10 April 1959 or later.

(10)

For concessions granted before 10 April 1959, the concession power price is calculated as a function of the individual power plant’s cost-price, plus a premium of 20 %. This model is still applied to concessions granted prior to 10 April 1959, and is in the following referred to as the ‘cost price’ model. Concession power sold according to this pricing model is in the following referred to as ‘cost price concession power’.

(11)

For concessions granted after 10 April 1959, the concession price is set by the Ministry of Energy and Petroleum on the basis of the average cost for a representative sample of hydroelectric plants throughout the country. This pricing method is in the following referred to as the ‘ministry price’ method. Concession power sold according to this pricing model is in the following referred to as ‘ministry price concession power’.

(12)

The Industrial Licensing Act provides that the municipalities entitlement to concession power may be brought up for review by Norwegian Water Resources and Energy Directorate (‘NVE’) 20 years after the concession was granted (13). The Norwegian authorities have explained that while the review process can lead to a fine-tuning, by NVE, of the volume of concession power, it cannot lead to substantial changes of the municipality’s entitlement to concession power. The majority of Narvik’s concession power entitlements are due for review in 2019.

(13)

The municipalities carry the cost of feeding the concession power into the grid.

(14)

Per year, Narvik is entitled to a total of approximately 128 GWh of concession power, of which approximately 116,3 GWh is priced according to the ministry price method and the remaining approximately 11,7 GWh is priced according to the cost price method. The Norwegian authorities have explained that the ministry price in 2000 was approximately NOK 0,10 and the relevant cost price for Håkvik and Nygård in 2000 was in the range of NOK 0,14 to NOK 0,178.

(15)

NEAS is located in Narvik municipality in the county of Nordland. It produces and sells electricity. Until 2001, NEAS was 100 per cent owned by Narvik municipality. In 2001, Narvik sold off 49,99 % of its shares to two power companies, Vesterålskraft AS and Hålogalandskraft AS.

(16)

After a merger in 2006 and a name change in 2009, NEAS is now part of the company Nordkraft AS (‘Nordkraft’).

(17)

Until the end of 1998, Narvik sold its annual entitlement of approximately GWh 128 of concession power to NEAS under short- or longer-term contracts. However, at the beginning of 1999, after failing to reach an agreement with NEAS, Narvik sold its concession power on a power exchange at spot prices.

(18)

In March 1999, the municipality arranged a tender procedure for the sale of its concession power for the remainder of 1999. On 30 March 1999, Narvik concluded a contract with the highest bidder, Kraftinor AS. The price was NOK 109,50 per MWh. Since it paid NOK 111,10 per MWh plus feeding costs of NOK 20 per MWh for the concession power, Narvik incurred a loss of approximately NOK 2,3 million under this contract. Narvik had initially expected a surplus of NOK 3,5 million.

(19)

On 19 October 1999, the Municipal Council Executive Committee (‘Executive Committee’) recommended to the Municipal Council that the overall goal for handling the municipality’s concession power should be to maximize return on a long-term basis in order to obtain a stable planning horizon. The proposed strategy for achieving this goal had four elements:

(20)

The Municipal Council confirmed the recommendation of the Executive Committee with one adjustment, suggested by the Mayor and confirmed by way of an amendment to the strategy: instead of the Mayor being explicitly ‘granted power of attorney to enter into agreements according to the strategy decided by the Municipal Council’, the final decision stated that ‘as a first step in executing this strategy, NEAS is invited to discuss their interest in the matter as outlined in their letter to the municipality dated 9 November.’

(21)

A letter from NEAS dated 9 November 1999 questioned the proposed strategy of selling the concession power under different contracts of different lengths to diversify risk. Instead, NEAS suggested one long-term contract (‘for example 50 years’) and was open to including a price adjustment clause in the contract with Narvik.

(22)

Also in a letter dated 15 April 1999, NEAS stated its interest in entering into a long-term contract regarding the concession power, primarily through a purchase with an upfront lump sum payment, or alternatively as a long-term lease - suggested initially at 60 years - with annual payments to Narvik.

(23)

Aside from the issue of the concession power, there were also discussions about NEAS’ future role in the market, and Narvik’s role as the owner of NEAS.

(24)

According to the Norwegian authorities, NEAS was at the time observing extensive regional consolidation amongst power companies and the entry of national/international operators into local markets. NEAS needed to strengthen its equity base in order to acquire shares in other electricity companies, particularly Nordkraft AS. NEAS had also signed letters of intent with Hålogaland Kraft AS and Vesterålskraft AS to form a regional production company and a regional energy transportation company. These changes were planned to take effect as of 1 January 2001. In order for NEAS to be able to complete these transactions with a combination of equity and borrowed capital, Narvik - NEAS’ sole owner - was expected to inject additional equity into NEAS.

(25)

In a municipal council meeting on 16 December 1999, it was decided that the municipality’s ownership stake in NEAS, the company’s capital needs and the handling of concession power, should be assessed jointly by a negotiation team consisting of the Mayor, the Deputy Mayor, the leader of the opposition, as well as the Director, the Deputy Director and the Head of Procurement of the municipal administration (‘the negotiation team’).

(26)

NEAS commissioned two reports from Arthur Andersen (‘AA’) and Deloitte & Touche (‘DT’) in order to determine the value of the ministry price concession power. The AA report applies a net present value (‘NPV’) methodology, but does not describe the underlying assumptions in great detail. The DT report also utilises an NPV methodology, but goes further than the AA report in explaining relevant assumptions and calculations. For example, the DT report explains in detail how the required return is determined based on the capital asset pricing model (‘CAPM’) and how the weighted average cost of capital (‘WACC’) is determined. The analysis also contains a detailed description of the calculation of the concession price and include sensitivity analysis based on incremental changes in both the price of electricity and WACC.

(27)

Narvik commissioned two reports from Danske Securities (‘DS1’ and ‘DS2’). For the first report, DS1, Danske Securities was commissioned to assess whether or not the municipality should sell its entitlement to concession power in the market or transfer it to NEAS. In DS1, Danske Securities, on its own initiative, provided an estimate of the value of the entitlement to concession power for a period of 50 years. Apart from stating its assumptions made for future developments of electricity prices, Danske Securities provided limited guidance on how the value of the entitlement to concession power was calculated.

(28)

In DS2, Danske Securities requested price and cost expectations from 3 market operators: CBF Kraftmegling AS (‘CBF’), Norwegian Energy Brokers AS (‘NEB’) and Statkraft SF (‘Statskraft’). On the basis of these expectations, Danske Securities calculated an estimated market value of the entitlement to concession power. CBF’s expectations resulted in a base case estimate of NOK 127 million. NEB’s expectations resulted in a base case estimate of NOK 75 million. As NEB had not adjusted its price and cost expectations for inflation, Danske Securities stressed that it did not find NEB’s expectations to be credible. Statkraft’s expectations resulted in a range of NOK 115-140 million. On the basis of these three value assessments, Danske Securities concluded that the estimated NPV of the entitlement to concession power would be in the range of NOK 100-140 million.

(29)

The four reports are summarised in the following table. In the following, these reports are collectively referred to as ‘the four reports’.

(30)

In addition to the external advice, the head of procurement in Narvik municipality made his own assessments.

(31)

In the first assessment presented to the Executive Committee in October 1999, he concluded that the overall risk for the municipality was high for long-term contracts defined as contracts between 10 and 40 years.

(32)

In his second assessment, presented to the negotiation team on 16 March 2000, various options for handling the concession power were discussed. By this time, however, the negotiation team had narrowed the scope of his mandate to only assess risk, time to settlement, tax implications and profit maximization for three scenarios (all involving Narvik transferring the concession power right to NEAS for a 50-year period and reducing its ownership stake in NEAS). Notwithstanding this, in his second assessment, the head of procurement continued to focus on the importance of the length of the contract. His assessment of the marginal value of the entitlement to concession power over time was that ‘…to enter into a very long contract such as 50 years gives very little additional value for us as sellers compared to a shorter contract (for example 20 years with NOK 83 million)’.

(33)

After internal discussions regarding the advantages and disadvantages of a long-term contract, the negotiation team made its recommendation to the Municipal Council where it recommended a contract with a duration of 50,5 years as appropriate to reduce the municipality’s risk and to provide a long-term planning horizon.

(34)

NEAS had only sought to purchase the 116,3 GWh of ministry price concession power. In the negotiations with the company, Narvik however insisted that its entitlement to concession power be bought in full, and that the 11,7 GWh cost price concession power therefore be bundled with the ministry price concession power.

(35)

In May 2000, the parties finally agreed to have the full 128 GWh of concession power covered by the agreement and that NEAS would pay NOK 120 million for the ministry price concession power and NOK 6 million for the cost price concession power.

(36)

On 25 May 2000, the Municipal Council formally decided that the municipality should sell its annual 128 GWh entitlement to concession power to NEAS for 50,5 years for NOK 126 million.

(37)

On 16 October 2000, Narvik and NEAS formalised the agreement by signing the contract where Narvik sold the entitlement to concession power on the above described terms. No price adjustment mechanism was included in the contract, and the money was to be paid as an upfront lump sum.

(38)

On 29 November 2000, Narvik and NEAS signed a supplementary agreement where NEAS for the purchase of the entitlement to concession power committed to pay Narvik NOK 60 million in cash, and the remaining NOK 66 million as an equity contribution in kind injected into NEAS (at the time 100 % owned by the Municipality).

(39)

In 2001, Narvik divested 49,99 % of its shares in NEAS to Vesterålskraft AS and Hålogalandskraft AS.

(40)

The Norwegian authorities are of the view that the contract with NEAS was concluded at market terms. They firstly emphasise that the agreement was concluded because Narvik’s finances were strained and it was in need of liquid capital. Secondly, NEAS needed to undergo recapitalization in order to restructure the company to create a larger regional company. Lastly, at the time of the conclusion of the contract, the municipality had been selling concession power at a loss because the concession power price was higher than the price obtained in the market. By way of example, in the period April 1999 to December 1999, Narvik lost NOK 2,3 million on the sale of concession power.

(41)

As regards the question of regulatory risk, the Norwegian authorities have explained that NEAS bears all risk. They argue that the risk is likely to be one of reduced quantity rather than increased quantity of concession power which would reduce the likelihood of aid.

(42)

The Norwegian authorities argue that the appropriate market benchmark for the 50,5 year agreement is a permanent sale of a power plant, and that adjusted for relevant differences, the prices obtained by NEAS was in line with the price levels for the sale of power plants in the same period.

(43)

For price data about the sale of power plants in 2000, the Norwegian authorities refer to a so-called real time review of the electricity market for year 2000 carried out by Pareto (the ‘Pareto Review’). In that review, it appears that the market prices for power plants sold in 2000 varied between NOK 1,64 and 1,77 per KWh of annual production capacity. Narvik’s sale of entitlement to concession power equals approximately NOK 1,00 per KWh of annual production capacity. According to the Norwegian authorities, the difference between these figures can be explained by the following factors.

(44)

Firstly, in 2000, the typical operating costs including ongoing reinvestment (without depreciation) for a newer power plant was about NOK 0,05 per KWh per year (plus feeding costs). NEAS’ expected ongoing payment was twofold; about NOK 0,10 per KWh per year (plus feeding costs) on the ministry price concession power and between NOK 0,14 and 0,178 per KWh (plus feeding costs) per year on the pre 10 April 1959 concession power. In 2000, the expected market price was approximately NOK 0,12 per KWh. Thus, the 2000 scenario would lead to a net profit of NOK 0,07 per KWh for a plant owner, compared to NOK 0,02 per KWh on the concession power. At the time of the conclusion of the contract, the estimated 2010 price was NOK 0,20. On the basis of that estimate, the 2010 scenario would lead to a net profit of NOK 0,15 per KWh for a plant owner, compared to NOK 0,10 per KWh on the concession power.

(45)

Secondly, the Norwegian authorities argue that the prices for the sale of the five power plants from the Pareto Review must be reduced by approximately 10-15 % when applying a capitalisation rate of 4 % to make up for the difference between the capitalisation over infinite time (capitalisation factor of 25) and 50 years (capitalization factor of 21,48).

(46)

The Norwegian authorities further add that the early years have the greatest impact on the NPV calculation and that heavy reinvestment costs of ownership typically comes at a later stage, and therefore has little reduction effect on the NPV calculation.

(47)

Taking this into account, the Norwegian authorities argue that there is a close correlation between on the one hand, power plant sales at approximately NOK 1,64 – NOK 1,77 per KWh of annual production capacity, and on the other hand, rents (payment for electricity access for 50,5 years) of approximately NOK 1,00 per KWh of concession power.

(48)

The Norwegian authorities thus argue that a comparison which adjusts for these factors demonstrates that the price NEAS paid for the concession power was comparable to the price of power plants sold in the same period, and add that the conclusion on the price level is supported by the DT report and the two DS reports predating the conclusion of the 50,5 years concession power agreement.

(49)

In reference to the Authority’s Guidelines for state aid elements in sales of land and buildings by public Authorities (‘the SOL’) (16), the Norwegian authorities argue that a competitive and unconditional tender procedure is only one method recognized by the Authority to determine market prices on the sale of public assets. The Norwegian authorities emphasise that in the SOL, the Authority also recognises that an aid free market price can be established on the basis of an independent expert evaluation. The Norwegian authorities note that the DT and the two DS reports were delivered before the 50,5 year contract was concluded. The second DS report determined the value on the basis of ‘direct market research’, which according to the Norwegian authorities resulted in a market testing similar to that of a tender procedure. The Norwegian authorities also note that the final price was within the upper level of the three valuations.

(50)

The Norwegian Authorities further argue that it was appropriate for no price adjustment clause to be included, since the purchase price was paid as a lump sum, and not on an ongoing basis. The Norwegian authorities argue that the fact that the sale was settled up front – partly in cash and partly as a contribution in kind – similar to a permanent power plant sale, it is ‘unnatural and very unusual’ to include a price adjustment mechanism. The Norwegian authorities furthermore argue that by virtue of the contribution in kind model a subsequent adjustment would probably also have been illegal pursuant to the provisions of the Limited Liability Company Act (17).

(51)

One third party, NEAS (now Nordkraft), submitted comments to Decision 393/11/COL. NEAS essentially concurs with the views of the Norwegian authorities.

(52)

Article 61(1) of the EEA Agreement reads as follows:

‘Save as otherwise provided in this Agreement, any aid granted by EC Member States, EFTA States or through State resources in any form whatsoever which distorts or threatens to distort competition by favouring certain undertakings or the production of certain goods shall, in so far as it affects trade between Contracting Parties, be incompatible with the functioning of this Agreement.’

(53)

It follows from this provision that, for state aid to be present, the measure must confer an economic advantage on the recipient. In the following, the Authority assesses the question of the presence, in the case at hand, of such an economic advantage.

(54)

The Court of Justice of the European Union has stated that in order to confirm whether a state measure constitutes aid, it is necessary to establish whether the recipient undertaking receives an economic advantage, which it would not have obtained under normal market conditions (18). In order to assess the presence of an economic advantage, the Authority applies the principle of a (hypothetical) market economy investor (19).

(55)

If the transaction in question was carried out in accordance with the market economy investor principle, i.e., if the municipality sold the entitlement to concession power for its market value, and the price and terms of the transaction would have been acceptable for a prudent private investor operating in a market economy, the transaction would not confer an economic advantage on NEAS and thus not involve the grant of state aid. On the contrary, state aid could be involved if the transaction was not carried out at market price.

(56)

In making this assessment, the Authority cannot replace Narvik’s commercial judgement with its own, which implies that the municipality, as the owner of the concession power entitlement, enjoys a margin of discretion to choose the manner in which it operates under normal competitive conditions.

(57)

An assessment of the price and terms of the contract between the municipality and NEAS should be based on the information available to Narvik at the time of the conclusion of the contract. Generally, an informed ex ante assessment would be sufficient to exclude the presence of state aid, even if the assumptions used in the assessment prove to be wrong with hindsight.

(58)

In the following, the Authority therefore assesses whether Narvik acted as a private market investor when it entered into a contract to sell its entitlement to concession power.

(59)

The Authority is mindful of the context in which the transaction was entered into. From the information provided by the Norwegian authorities, the Authority understands that at the time the contract was entered into the municipality was in a situation where it needed both access to liquidity (in order to meet its loan obligations), as well as capital to inject into NEAS. In addition, it is noted that the Limited Liability Company Act restricted the possibility of incorporating a price adjustment mechanism in the contract when making a contribution in kind. In 1999, prior to the conclusion of the sales agreement in 2000, Narvik had furthermore incurred losses on its sale of concession power. The municipality had therefore decided to sell off its entitlement to concession power for a longer term whilst at the same time complying with its expressed strategy of maximising its return on the concession power.

(60)

The Norwegian authorities have argued that the Authority should be able to exclude the presence of an advantage by applying the principles of the SOL to the case at hand. The Authority notes that, although the SOL does not apply to the sale of entitlements to buy concession power, the SOL does indeed prescribe two methods with which public authorities normally can obtain a market price for the sale of publicly owned land and buildings and consequently ensure that the sale does not involve state aid. The first method to exclude an aid element is the sale through an unconditional bidding procedure. The second, the sale at a price established by an independent expert evaluation made in accordance with generally accepted valuation standards.

(61)

The Authority notes that the sale of an asset through an unconditional bidding procedure normally will exclude the presence of an advantage. At the least in genuinely open procedures where there is more than one bidder (20). Narvik’s entitlement to concession power was however, not sold through an unconditional bidding process.

(62)

On the other hand, Narvik and NEAS each commissioned two assessments from external advisors, as described in paragraphs (26) to (29) above. However, neither the DS1, the DS2 nor the AA reports thoroughly clarify what method is used to determine the value assessments. In the absence of further clarifications, the Authority is not in the position to assess whether the market value assessments have been made in accordance with generally accepted market indicators and valuation standards. Therefore the view of the Authority is that the DS1, the DS2 and the AA reports are of limited value in assessing the value of the entitlement of the concession power. On the other hand, the DT report does provide a detailed explanation of its assessments. Consequently its results can be tested and verified. The Authority therefore finds that the DT report is the most credible report. In the view of the Authority, the fact that all of the four reports give similar results (21) however strengthens the results of the DT report and arguably also those of the three other reports.

(63)

The Authority notes that although a price determined by an independent value assessor normally can be held to exclude the presence of an advantage in the sale of easily appraisable generic land or buildings that have been subject to numerous transactions, this is not necessarily the case for land and buildings with more unique qualities or where the circumstances surrounding the sale are liable to cast doubt on whether the expert evaluation reflect the actual market value of the property (22).

(64)

As explained in the following, fixed price power supply contracts of a duration exceeding 6 years are unusual and not commonly observed. Due to the lack of a market where comparable prices can be observed and due to the volatility of electricity prices, an expert evaluation is less suitable as an instrument to determine the market price of a fixed price 50,5 year power contract (23).

(65)

In any event, the Authority recalls that it is the market economy investor test, and not the SOL, which concerns sale of public land and buildings, that is the applicable test to assess whether a power contract concluded by a public authority involves an advantage ‘favouring’ an undertaking. Indeed, that the general market economy investor principle applies to long term power contracts, has been confirmed by the General Court in Budapesti Erőmű Zrt v Commission where the General Court endorsed the approach taken by the European Commission (‘the Commission’) in a case concerning long term power contracts concluded by the Hungarian authorities (24).

(66)

In that case the Commission identified the main practices of commercial operators on European electricity markets that were relevant for the purposes of its analysis and assessed whether the agreements in the case at hand were in line with those practices, or whether the contracts were concluded on terms that would not have been acceptable to an operator acting purely on commercial grounds (25).

(67)

The Commission found that long term power contracts with a duration of more than 6 years are rarely concluded on the European market (26). The information available to the Authority confirms this finding. There are therefore few if any long term power contracts with which to benchmark the price of power sold for 50,5 years into the future.

(68)

Long term estimates of future power prices do however have to be made by potential buyers and sellers of power plants. It is on this basis the Norwegian authorities have argued that the sale of Narvik’s entitlement to concession power should be likened to the sale of a hydro power plant. To support this argument, the Norwegian authorities have provided the Authority with the Pareto Review which gives an overview over five hydro power plants sold in Norway in the year 2000.

(69)

The Norwegian authorities argue that both in the case of a hydro power plant sale as well as Narvik’s sale of its entitlement to concession power, the sales prices represent the NPV of the expected cash flows of the production volume. Thus, like Narvik and NEAS in the case at hand, any buyer or seller of a hydro power plant will have to assess the plant’s value based on expected production incomes minus expected costs discounted at a relevant discount rate for as long as the new owner can exploit the relevant hydropower.

(70)

The Norwegian authorities argue that, corrected for certain relevant factors, the prices of the five hydro power plants mentioned in the Pareto report are comparable to the price obtained in the sale of Narvik’s entitlement to concession power. In this context, the Authority notes the correction factors referred to by the Norwegian authorities, as explained in chapter I.11 above.

(71)

For the five hydro power plants, the range of sales prices per KWh of production capacity was between NOK 1,66 and 1,74. A permanent sale of an asset will increase the NPV of the asset compared to a sale of the entitlement to purchase concession power over 50,5 years, as the asset is assumed to have positive cash flow beyond year 50,5. The Norwegian authorities have assumed a 4 % capitalisation rate which result in a downward adjustment of the sales price by approximately 10-15 % in order to compare a permanent sale with the time limited concession power sale (27).

(72)

The second difference between a permanent sale and a sale of the entitlement to purchase concession power over 50,5 years concerns the cost base to use in the NPV model – total production costs vs. the concession price. The Norwegian Authorities have argued that the typical operating cost including reinvestment for a newer power plant was approximately NOK 0,05 per KWh while the ministry price at the time was approximately NOK 0,10 per KWh.

(73)

In order to assess whether the prices for the power plants constitute appropriate proxies for the market price of the concession power at issue, it is necessary to look at each element of the argument in more detail. The Authority’s assessment is based on information provided by the Norwegian authorities and other publically available information.

(74)

In the following analysis nominal figures are used in all calculations (28).

(75)

For the five hydro power plants mentioned in the Pareto Review, the sales prices per KWh of production capacity was in the range from NOK 1,66 to 1,74. In a report issued by the economic consultancy firm Econ Pöyry analysing power plant sales between 1996 and 2005, the average transaction value in the year 2000 appears to be somewhat higher, estimated at approximately NOK 1,85. According to the same report, the same approximate price was obtained in 1999. Accordingly, the price range to compare with appears to be slightly higher than the one in the Pareto Review. Since the ECON report refers to a higher average transaction value than the Pareto review, the Authority will use a range of NOK 1,70 to 1,80 in the further analysis.

(76)

The second factor to consider is how to adjust price levels from a permanent sale to a time limited sale over 50,5 years. The Norwegian authorities have argued that the appropriate adjustment factor is 10-15 % based on a capitalization rate of 4 %. The Authority finds that the choice of capitalization rate is closely linked to the choice of discount rate in the NPV model. The nominal after tax discount rate that was used in the DT report was 6,8 % while the AA report used 7 %. It is also noted that NVE has used a 6,5 % rate when assessing new hydro power plant projects (29). The cost price calculation model uses a 6 % rate (30). The Authority is, on the basis of the above, of the opinion that the appropriate discount rate and hence the appropriate capitalisation rate to apply when comparing a permanent sale to a time-limited sale, is in the range of 6-7 % nominally after tax. On this basis, the appropriate adjustment of value from a permanent sale to a 50,5 year sale is not 10-15 % as argued by the Norwegian authorities but closer to 4-5 %.

(77)

The third factor to consider is the expected future market price of electricity. As explained above, forecasting future power prices for 50 years or longer is an exercise fraught with difficulty. In the valuation reports described above, in particular the AA and the DT report, the market price of power was expected to increase steadily for a period of 10-20 years beyond which the prices were expected to be constant in real terms (i.e. only increase with expected inflation) (31). This suggest that the consensus in the market at the time was that future power prices in the long term would remain constant in real terms and not continue to increase (32). The Authority assumes that the same uncertainty about future power prices was present for all market participants, also those that were buying and selling power plants during the same period as the sale of the concession power entitlement. As such, there is no reason to assume that different market participants have access to significantly different information concerning market price expectations.

(78)

Moving from revenue to costs, the comparison presented by the Norwegian authorities refers to a scenario where there is a difference in cash outflows per KWh between a permanent sale and the sale of concession power of NOK 0,05 due to an expected concession price of approximately NOK 0,10 and an operating cost including reinvestment of approximately NOK 0,05.

(79)

As regards the ministry price for concession power, the consultants who advised Narvik and NEAS expected the prices to remain relatively constant in real terms meaning that neither significant efficiency gains nor great volatility in the cost base was expected. In principle, the ministry price for concession power was expected to increase with inflation (33). Based on the available information, the Authority is of the opinion that the same assumptions would have been made by a prudent investor and therefore assumes that there would be no major changes to the cost price concession power price in the further analysis. These costs make up the relevant cash outflow in the calculation of the value of the concession power (34).

(80)

As there are a number of variables that can affect the level of cash outlays over time, the NOK 0,05 figure combining operating and reinvestment cost needs to be assessed based on its various components.

(81)

Firstly, it is apparent that a power plant will have a certain level of general operating and maintenance costs. It is assumed that the operating and maintenance costs of a hydropower plant generally is relatively low and constant in the range NOK 0,02-0,05 per KWh (35). This is supported by the cost data used to determine the ministry price. In 2000 the compensation under that model for operating and maintenance costs were NOK 0,267 per KWh.

(82)

Also other cash outflows are relevant for the NPV calculation. In the ministry price calculation from 2000 taxes were compensated with NOK 0,021. The actual tax levied on a given power plant would of course depend on the profits but given that the ministry price is intended to be representative for the average cost of typical power plants in Norway, it appears reasonable to assume a tax cost of approximately NOK 0,02 per KWh.

(83)

The final part of the cash outflows in the NPV is the reinvestment costs which depend crucially on the timing and level of reinvestments needs of the power plant. The Authority understands that, for accounting purposes, the economic lifetime of a hydropower plant is 40 years (36), however the actual lifetime may be longer. The level of reinvestment is in many cases substantial, and therefore the timing of the cash outlay, as also argued by the Norwegian authorities, is of great importance to the NPV calculations. If the reinvestment occurs early in the calculation period, the reduction in NPV is significantly larger than if the reinvestment takes place later in the calculation period. However, the Norwegian authorities have not provided the Authority with information on the reinvestment needs of the hydro power plants sold in 1999 and 2000 that they use as a basis for their comparison. The Authority notes that it is likely not readily available nor easily obtainable due to its age and presumably business sensitive nature.

(84)

When adjusting the prices for the hydro power plants in question for the two differences mentioned above, the time period and the cost base, the Norwegian authorities argue that the price range of NOK 1,66 and 1,74 per KWh is comparable to the price obtained on the concession power of approximately NOK 1,00 per KWh (37). As explained above, the information available to the Authority indicates that the average transaction value for 1999 and 2000 was somewhat higher than this range (approximately NOK 1,85). Therefore, the Authority will compare a price range of NOK 1,70 to NOK 1,80 per KWh with the price of NOK 1,00 obtained by Narvik.

(85)

The first adjustment would be to make the permanent sales prices comparable to a 50,5 year contract. The Authority have used a capitalization rate of 6 % which reduces the permanent sales values by approximately 5,5 %. The comparable range of prices obtained in power plant sales is therefore NOK 1,61-1,70. The difference in net cash flows of NOK 0,61-0,70 per KWh between concession power prices and the operating cost of a power plant would have to explain the difference in order to satisfy the market investor test and exclude aid.

(86)

Total operating cost are as mentioned above estimated to be in the range NOK 0,02 to 0,05 per KWh plus estimate NOK 0,02 per KWh in taxes, which equals NOK 0,04-0,07 per KWh. In addition, reinvestments have to be taken into account, the financial effect of which depends on timing and size and are therefore difficult to quantify.

(87)

Taking this into account, the Authority has carried out a sensitivity analysis on the sale of the 128 GWh (38) of concession power over the 50,5 year period. The Authority has tested various combinations of costs and discount rates with nominal after tax discount rates ranging from 5,5 % to 7,5 % and total operating costs between NOK 0,05 and 0,09 per KWh, as demonstrated in the table below.

(88)

The results are below the NOK 0,61 to NOK 0,70 range in the case where the operating costs are NOK 0,09 at any discount rate in the 5,5 % - 7,5 % range or in the case where both the operating costs are NOK 0,08 and the discount rate is 7,5 % or higher. In these scenarios the difference between the concession power price and the operating cost is so small that when the NPV of the difference is calculated, it does not explain the difference in the higher prices obtained in the permanent hydro power plant sales. However, this is the case only in situations where the operating cost, when reinvestment costs are included, are 60 to 80 % higher than the cost estimates put forward by the Norwegian authorities.

(89)

The Authority has assessed the question of whether Narvik’s agreement with NEAS conferred an advantage on the latter on the basis of the information provided by the Norwegian authorities. The Authority has found the four expert evaluations to be of limited value. There are numerous uncertainties connected to the developments of future electricity prices over longer periods. Long term power contracts without price adjustment clauses are unusual.

(90)

Moreover, it is not obvious that the sale of power plants as such can be compared with a sale of concession power since a permanent sale is a final decision for which the risk concerning the infinite or future value must be assessed. This is not the case of concession power sale where the optimal length of the contract in terms of risk and value might be different.

(91)

However, the Authority has taken note of the particular circumstances of the case including the fact that Narvik suffered losses on the sale of concession power just before the 50,5 year contract with NEAS was concluded, coupled with the fact that the municipality needed access to liquidity in order to both repay its debt as well as making the planned investment in NEAS.

(92)

It is in the light of these particular circumstances that the Authority accepts the argument that the transaction at issue, despite its very long duration and the uncertainty about future power prices, may be compared with hydro power plant sales that took place in 1999 and 2000. The Authority thus, in this particular case, accepts that the prices for the hydro power plants sold represent an adequate proxy for the market price in the long term sale of concession power entitlements at issue. Based on the evidence made available to the Authority by the Norwegian authorities, and the explanations about the relevant differences, it appears that Narvik obtained a price comparable to the power plant sales of 1999 and 2000.

(93)

On the basis of those elements the Authority has, on balance, come to the conclusion that Narvik, when it concluded the contract with NEAS for the sale of its entitlement to concession power acted within its discretion as a market economy investor.

(94)

The contract therefore cannot be considered to confer an advantage on NEAS and consequently, it does not involve state aid within the meaning of Article 61 of the EEA Agreement.