Reconciling competitiveness and environmental objectives

Applied Energy 76 (2003) 75–87 www.elsevier.com/locate/apenergy

Reconciling competitiveness and environmental objectives§ Adriaan Perrels* Government Institute of Economic Research (VATT), PO Box 269, Ha¨meentie 3, 00530 Helsinki, Finland Accepted 4 February 2003

Abstract The liberalisation of electric-power markets has mixed implications for the upkeep of environmental policies. A further regulatory completion of the liberalisation of electric-power markets within a sound social-economic and sustainability setting requires steps that incite the introduction of capacity-scarcity signals (e.g. ToD pricing) in the retail-pricing structure. As a consequence, efforts for environmentally-benign conversion options and energy efficiency will go up. A great challenge connected with this step is the rearrangement of risk-assessment practices and the handling of risks. # 2003 Elsevier Ltd. All rights reserved. Keywords: Electricity market; Environmental policy; Energy saving; DSM

1. Introduction In many OECD countries, the electricity-supply industry has been reorganised and the sector is often still in a stage of transformation. In generic terms, the common philosophy is and was that there is less justification for extensive public intervention. New insights in the use of economic policy instruments and new technologies would enable ever better than before to treat electricity in many ways as a ‘normal’ good. That said, it is however quite evident that deregulation of the electricity-supply industry mostly means re-regulation. In various liberalised electricity markets, such as in the UK, the market design has already undergone §

Views expressed in this paper only represent the views of the author. * Tel.: +358-9-703-2972; fax: +358-9-703-2969. E-mail address: adriaan.perrels@vatt.fi (A. Perrels).

0306-2619/03/$ - see front matter # 2003 Elsevier Ltd. All rights reserved. doi:10.1016/S0306-2619(03)00049-7

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Nomenclature CHP DSB DSM ESCO RECS ROI ToD PVO TVO

Combined Heat and Power Demand Side Bidding Demand Side Management Energy Service Company Renewable Energy Certificate System Return on Investment Time of Day Pohjolan Voima Oy (Finnish power company) Teollisuuden Voima Oy (Finnish power company)

far-reaching revision. Compared with other liberalised electricity-markets, the Nordic electricity-market has been performing satisfactorily (at least according to most Finnish market players [1]) and has seen a steady increase of its service area (Nordpool) from only Norway (1991) to Sweden (1996), Finland (1998) and Denmark (1999 and 2000). Also in terms of available trading products, the portfolio has been widening steadily. It should be stressed that the market organisation differs by country, thereby allowing for retention or re-establishment of some market power [2]. Apart from ensuring a proper functioning of the electricity market as such, public authorities are concerned about the pursuit of other policy goals such as (national) security of supply and environmental-performance targets. Instruments aiming at the achievement of security of supply and environmental objectives usually affect the functioning of the electricity market. This paper focuses on the need for new generation and transmission capacity in the Nordic market and Finland in particular, with special reference to environmental policies. With this compound theme, effective market-design, security of supply, and the transition towards a sustainable energy system come together.

2. The Nordic power market and concerns about capacity Notwithstanding the successful performance up to now (i.e. significant cost moderation and very few supply disruptions), there are concerns for the future, notably with respect to the ability to meet demands at reasonable prices. For a long-time, prices on the Nordpool exchange were fairly low, though since last year the price level in the Nordpool area has been elevated to a higher level (see Fig. 1). It remains unclear whether this trend will continue or a new—possibly temporary—stabilisation occurs. The question is whether the market is far sighted enough to allow generators to add capacity timely, that is, before serious and lasting price increases occur.

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The large share of energy-intensive industries in the economy and the close ties between governments and main generators ensured, in the pre-liberalisation period, a top priority for low electricity prices for very large consumers. These are still important for generators since they provide a significant amount of base-load demand and thereby ensure high utilisation rates for the capital-intensive generation capacity. Yet, their relative significance is smaller nowadays. As a consequence, the share of sales to customers with a high price-elasticity diminished for most electricity companies. The extent to which generators can cash in on these changes depends on their company structure (vertically integrated or generation only), on the extent they can sell via the power exchange, and on the flexibility in their sales portfolio (long, short, and power exchange contracts). The prevailing stance among most key Nordic generators seems to be that average spot price level (‘Elspot’) should be sufficiently high to merit new investments with a ROI of more than 10%. The risk is that the investment triggering price level is reached in a market context that implies quick further price increases, whereas the extra capacity resulting from the investments comes in line 2–5 years later. The likelihood increases that Sweden and Norway can have a net import need simultaneously with Finland (see Table 1). The extra relief that could come from Russia is helpful, but probably limited.1 Table 1 shows the reported reserve margins in 2000 according to Eurelectric [3] and also the expected coverage of maximum loads in a dry year for the years 2003–20052 issued by Nordel [4]. However, since precipitation varies from year-to-year, extra capacity causes more idling in not-wet years. Observing this

Fig. 1. Spot prices in the Nordpool area 1998–2002 (March). 1 2

A new border crossing transmission-line of 400 kVA will be built between Finland and Russia. Dry means here a low level of precipitation with an occurrence probability of 10%.

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problem it seems attractive to extend the transmission line capacity, especially by involving a larger variety of systems. Therefore, next to the addition of lines between Finland and Russia and the new line between Norway and the UK, the considered lines between Estonia and Finland, between Norway and the Netherlands (and between the Netherlands and the UK) and reinforcement of the lines through Denmark would significantly alleviate the need for extra power in the Nordpool area.3 The wholesale price levels in Western-Europe are still substantially higher than the Nordpool wholesale prices, consequently it remains to be seen what the price effects are on the Nordic market when many links are added. Some tendency to convergence is likely without achieving actual equalisation. Higher security of supply with limited capacity additions would most probably imply higher average wholesale price levels in the Nordpool area, but also a prevention of frequent price-hikes and occasional very expensive winters.

3. Demand and supply Norway has a virtually CO2-free electricity production and Sweden produces very few emissions. Both countries are facing a large challenge of how to keep their generation systems (almost) CO2 free given their Kyoto targets. Finland produces almost half of its electricity CO2 free (see Table 2) and this share is increasing. Thanks to the Renewable-Energy Programme (subsidies, RD&D support), the share of biomass in the Finnish fuel mix goes up. The introduction of tradable green certificates (RECS) may elevate the profitability of biomass-based capacity thanks to the extra demand from Western-European countries. This could boost the penetration of biomass in Finland even beyond the targets of the Renewable Energy

Table 1 Current reserve margins in Nordic countries and expectations for 2002–2005 Country

Reserve margin in 2000 (%)

Dry year power balance estimates at peak demand moment

Norway Sweden Finland Denmark

6 12 21 >30%

800 MW 1000 MWa 2500 MW 3000 MWb 400 MW 800 MWc +500 MWd

Source: Eurelectric (2001); Nordel (2001). a Import from Denmark (partly originating from Germany) and UK (if line is ready in time). b Import from Denmark (partly originating from Germany), Poland, and Finland (largely originating from Russia). c Import from Russia, partly re-exported to Sweden. d Export to Sweden and Norway, partly originating from Germany.

The recently reached agreement on uniform cross-border transmission fees (1 E/MWh) in Europe could affect the trade volume inside Nordpool. Impacts on trade with third countries are supposedly low [5]. 3

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Programme.4 Additionally, the construction of a fifth nuclear-unit is considered, which—in case of realisation—would further lift the share of CO2-free electricity generation. If no extra nuclear unit is installed, the use of biomass and in particular that of natural gas would be increased, and the energy saving would be further intensified according the official National Climate Strategy [6].5 On the supply side, there seem to be sufficient alternatives to ensure a reduction of greenhouse-gas emissions in electricity generation in the first commitment period of the Kyoto Protocol. One could claim that—even though the use of biomass and natural gas is expected to grow in all scenarios (incl. extra nuclear)—the various options are to some extent competing with each other. This competitive factor gets stronger the more stress is put on electricity saving. The progress in energy saving and energy efficiency is less tightly secured in Finland. From a long-term perspective, this is a potential weakness as transition towards a sustainable energy system is greatly facilitated by containing the growth in electricity demand (without containing the underlying growth in well being). In Sweden, the containment of growth of electricity demand is of utmost importance given the selfimposed limitations to phase-out nuclear capacity and replace them with nonnuclear capacity [7]. In Norway, the growth in demand cannot be accommodated by more hydro capacity, whereas the import possibilities from Sweden (due to its own policy), Denmark and the UK can only provide temporary relief if demand levels are not stabilised soon. Summarising, Norway has to step up its—up to recently low key—electricity-saving policy, whereas Sweden has intensified that already and last, but not least, Finland is somewhat hesitant regarding energy saving and tries to give a higher priority to sufficient CO2-free supply-capacity. The dissimilarity of Nordic national energy-policies reinforces the caution among investors to add significant amounts of capacity. Until 2 years ago, there was no Table 2 The fuel mix of Finnish electricity-production in 2000 Fuel type

Percentage share in the generation mix by source

Coal Peat Oil Natural gas Nuclear Renewables of which - hydro - wind - biomassa

10.8 5.7 1.9 10.0 27.3 30.1 18.3 0.1 11.7

Source: Eurostat NewCronos.

4

Large sales of green certificates in conjunction with conditions specified in the (draft) EU directive on the trade of CO2-emission allowances possibly necessitates a review of the Renewable Energy Programme. 5 The Climate Strategy can be expected to be revised in the near future, inter alia in connection with the introduction of international emission-permit trade.

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urgent need for extra capacity, but the prospects are starting to change. As a consequence of the ‘holding back’ investor attitudes, Russia has become an important source of imported electricity for the Nordic countries. Though growth in import levels is still feasible from a pure technical or technical-economic point of view, there are various other considerations, such as security of supply and global sustainability criteria, that probably will imply a virtual ceiling for the import volumes from Russia. This will not affect the growth of imports from Russia in the short run.

4. System load trends in Finland The annual growth rate of Finnish electricity-demand between 1970 and 2001 has been 4.35%. In the second half of this period, the annual growth rate was 2.85% [8,9]. The variation in the development of annual consumption depends largely on two factors, namely economic cycles and the weather (i.e. harshness of winters). There have been no dramatic swings in end-use price levels, although the decrease of real term price levels in the second part of the nineties, has assisted demand growth on top of the impact of a booming economy. As the relative share in the national economy of the heavy industry is declining, the impact of economic cycles on the variation in the development of demand is diminishing. This can be seen in Fig. 2 (line C-step—annual % growth of electricity demand). In the same figure also the development of the annual maximum load is shown (line L-step—annual % growth in maximum load). As the influence of the economic cycle is diminishing, the average level of the growth of maximum load is slowing down (the relation between maximum-load growth and annual demand

Fig. 2. Year-to-year developments (in%) in aggregate consumption (C-step) and in the maximum system load (L-step).

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growth is virtually one-to-one). However, in contrast to the diminishing amplitudes in the annual growth series, the year-to-year variation in maximum load levels (expressed as a %) is not diminishing, since it is predominantly determined by the variation in weather conditions. Swings of 10% are still possible. However, whereas 10% represented  350 MW in 1971 it represents  1300 MW in 2001. The number of hours of peak demand per year is not large ( 500 h). This is in itself already a reason in a liberalised market to try to rely on purchase contracts (imports) instead of installing more power. On top of that, the large variation in the development of maximum loads reinforces the tendency to rely on purchased (i.e. imported) power. Regardless of other factors, such as the higher ROI for new capacity compared to pre-1995 capacity, the high absolute-load variations causes investments in power generation capacity to be more risky.

5. Price developments and investment triggers in Finland From 1998 up to the end of 2000, seasonal price fluctuations were of the same order of magnitude as can be seen in the repetitive pattern in Fig. 1. In 2000, the prices in Sweden and even more so in Finland showed various deviations from the system price. The prices in the year 2001 are right from the start higher (due to harder winter-conditions) and also remain at a much higher level in subsequent months compared with the previous years (1996 had also high prices). The average price for the first three months of 2002 (20 E/MWh) is lower than the annual average of 2001 (22.8 E/MWh). Apparently, prices are coming down again, but may not return to the pre-2001 levels. The wholesale prices, as discussed above, apply to roughly 25% of the delivered electricity in Finland. The rest of the delivered electricity is sold through bilateral medium-term contracts and via vertical integrates, meaning that the distribution/supply company of the same holding buys for an internal trade price from the generator and sells to the final customer (services, households and small industries). Prices in bilateral contracts depend on the expected wholesale spot-price, past spot-price behaviour, the particular delivery conditions of the client and competing offers from other suppliers. The buyers are either distribution companies (and traders) or large consumers and are always very price sensitive. Therefore, only if wholesale price rises (Elspot) prove to have a more structural character, bilateral contracts will absorb (a part of) the price increase, albeit with a delay. In order to loose as little demand as possible, both generators and distributors/suppliers have an interest in transfering a disproportionate large part of the cost increases to price insensitive customers. Vertical-integrated companies have the best opportunities to do so. For integrated companies (Fortum, Vattenfall, larger municipal companies), price increases on the wholesale market are therefore not very problematic as long as the price rise is gradual. Traders and smaller municipal companies, with limited own capacity, can become more exposed to risk in these circumstances. A special case in Finland is the vertically-integrated TVO/PVO cluster, which can be typified as a

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co-operatively outsourced generation branch of various heavy industries in Finland.6 The very purpose of that company is to cater for cheap and reliable electricity generation for the shareholders (industries and some municipal energy companies). This means also that TVO/PVO is selling (or transferring) most of its production via bilateral contracts to the shareholders. Several of the co-owning industries have electricity-trading companies that resell part of the generated electricity depending on their own needs and the spot price. Other companies have a ‘holding back’ approach: under current circumstances, TVO/PVO will be soon inclined to invest in additional capacity, provided the greater part of the extra production is sure to be sold via bilateral contracts. Instead of profit maximising, this behaviour could be described as aiming for minimum regret for the energy cost of the shareholders. Regret in this case relates to overestimation of future electricity-demand sellable via bilateral contracts and to a more frequent occurrence of periods with low spot-prices. Current estimates for the unit cost of newly installed power vary between 25 and 30 E/MWh for large baseload units (nuclear, industrial CHP) to around 30–35 E/MWh for dayload units (CC gas) [10,11]. CHP in district-heating systems is somewhere within these ranges, depending on the scale and the fuel mix (natural gas/peat/biomass). The unit cost indicators are based on the assumption that requirements regarding the return on investment (ROI) go up in a liberalised market, as the generators are more exposed to a competitive capital market. Instead of applying a 5% real interest rate, as was usual in a protected utility environment, it is appropriate to apply a ROI of 10–15% (nominal rate) depending on the funding structure and the inflation rate. The above unit cost represents the total cost per sold unit (MWh) anticipating a typical runtime (e.g. 7500 h for baseload and 4000 h for dayload). Marginal costs per MWh are much lower, being about 8–10E for baseload and 17–20E for dayload. This means that, in the case of a large baseload unit, a profit-maximising investor is reluctant with present wholesale price levels, since in the case of baseload units one needs to ensure a good part of the sales via bilateral contracts. As mentioned above, these follow the spot-price developments with a delay and perhaps not wholly. For day-load capacity, it does not look much better. It might be possible to sell a good part of the production on the basis of spot prices, but the unit has to run appreciably more than 4000 h per year to generate a profit, if any. If it would run 7500 h, of which 3750 h are sold at 23E bilaterally and the spot price would be 24E on average for which it manages to run and sell another 3750 h, in that case, it would approach its minimum ROI. It should be stressed however that 7500 h is very high for such a unit, whereas the naturalgas price should not increase more than expected. One can predict that, only if the wholesale spot price in the Nordpool area starts to reach an average level of 26–27 E/MWh, will the investment trigger be reached. That would imply average price levels of about 15% above the 2001 levels, whereas an increase of peak levels is

6

It’s fair to say that a minor, but still significant, part of the production is consumed by non-industrial customers.

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supposedly still higher as the relation between the trend line and the price variation is often heteroskedastic.

6. Linking wholesale and retail markets better Currently wholesale prices are translated into retail prices on the basis of average price developments and with a considerable delay.7 This means that the demand side—apart from some large industrial buyers with direct access to the spot market—will not respond quickly in the case of high wholesale prices. As has been shown before, this leads to a potentially risky situation in the Nordpool area. When capacity gets tight, the end users do not notice it and will continue their demand patterns since they do not receive scarcity signals. Furthermore, high demand-levels are usually reached in cold winter days. A part of the extra demand stems from electric heating, which is for the greater part provided to households against a low tariff, whereas in those periods the actual value (spot price level) of electricity exceeds this tariff. For example, spot-price levels can be 30–50 E or higher (see Nordpool web site [18]), whereas the electricity component of the electric-heating tariff is only 18.5 E/ MWh (pre tax) [12]. Now the surplus capacity is largely eliminated in the wholesale competition, the retail pricing structure appears to have manoeuvred the electricity companies into a prisoners dilemma. The competition has been almost exclusively focused on the ability to provide sufficient low-price electricity. Sticking to this strategy might be possible in the short run as long as (integrated) companies manage to exploit price discrimination to the maximum by offering reasonable priced bilateral contracts to large consumers and concentrate the cost increases in the non-price sensitive part of the market. Occasional price hikes on the spot market can be partly offset by means of financial derivatives available in the Nordpool power exchange. In the long run, with ongoing price increases and more frequent price-hikes, they will need to raise tariffs more generally, whereas risk offsetting would get less cost-effective. As indicated before, there is a significant risk that most market players are underestimating the speed of price-increases related to a tightening capacity situation. The answer to this is to organise more structural links between capacity scarcity and the retail market. The overall catch word for this is Demand Side Management (DSM). In the eighties, DSM programmes were very popular in the USA [13] and to a lesser extent also in Europe. In the past few years, various authors and organisations [14–16] have already recognised that the liberalisation caused market players to focus on the wholesale market and perceive electricity predominantly as a bulk product and consequently neglect DSM. The (re)introduction of DSM would be greatly assisted when it is accompanied by a branding strategy of electricity companies. This means 7

There is also a tendency—as far as allowed by the electricity market authority—to raise the network component instead of the kWh component for small and medium sized customers.

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that instead of providing electricity only as a bulk-product, other brands are also available such as ‘green’ and ‘grey’ (interruptible) electricity as well as ‘layered’ purchase portfolios (e.g. part bulk, part green, part interruptible). This paper however focuses on DSM. DSM can involve the following segments:  customer specific load-management contracts, including inter alia deals on interruptability in exchange for tariff reductions (these measures are relevant for large industrial users)  more generic DSM support partly web/brochure based, with supplementary customer specific advice (these measures involve mostly quick scans to pick easy implementable cost-effective measures such as illumination retrofits in service-sector buildings, but can also concern the design of new buildings)  retail pricing scheme reforms, introducing the possibility of switching to timeof-day pricing with several levels of sophistication, depending on the initial cost (extra metering) and the expected net benefits  demand-side bidding (DSB), in which case the retail market is drawn into the wholesale market decision making: it means that market parties can ponder to buy sufficient capacity for period t against the option to buy offdemand in period t, i.e. compensate consumers for demand not fulfilled in period t [16].8 6.1. Example The introduction of demand-side management (DSM) notably through the connection of the wholesale (spot)price variations to the retail prices will affect demand patterns in two ways. On the one hand, it will cause a shift of demand from peak to off-peak periods. On the other hand, it will cause savings of electricity, since, in some cases, it is much easier to continue the use patterns of the involved types of equipment, but substitute or upgrade them for more efficient versions. Lighting is typically an application where saving is meaningful, whereas shifting is not. In the example, it is assumed that simplified Time-of-Day pricing is introduced for selected customers, whereas some accompanying marketing campaign effort is made as well. In the reference case, electricity demand at off-peak hours (peak and day time) are supposed to grow slightly faster than base-load demand (1.04 times the demand growth versus 1.00 times the demand growth, which represents the difference in the past decades). In the DSM case, all loads have the same growth rate, whereas the annual growth rate of consumption decreases from 1.8 to 1.6% per year due to DSM. The results are shown in Table 3 for the first year of the Kyoto commitment period (2008). The largest contribution, to the load reduction, comes from the reduction in demand growth. It would need extensive testing and (econometric) decomposition 8 This is the electricity market implementation of two optimal project-evaluation criteria in welfare theory, being the equivalence variation and compensating variation respectively. In ideal market conditions, they should give equal prices.

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A. Perrels / Applied Energy 76 (2003) 75–87 Table 3 Overview of impacts of introduction of DSM in the Finnish market

Default 2008 (MW) DSM 2008 (MW) Load difference (MW) Capacity effect (incl. reserve margin) and net increment (MW) Investment savings (mln. E) Cost and benefit summary (assumptions clarified in the text)

Base load

Day load

Peak load

9217 9083 134 152

11,583 11,354 229 261

15,058 14,760 298 298

152 228 Investment saved:

109 98

78 71 305 mln. E

Non-sold electricity (savings effect of DSM): Prevented yearly CO2 emission (0.3 ton/MWh): Lost margin on non-sold electricity: Campaign and extra metering cost (information, etc.): Value of prevented emissions (permit price 10E/ton):

1.47 TWh / year 0.44 Megaton 7.35 mln. E/year 20 mln. E/year 4.4 mln. E/year

analysis to underpin these kinds of simulations better. Given the lack of extensive direct empirical support, the assumptions regarding savings and pattern-change effects are therefore on the cautious side. For the avoided investments and the CO2 emission-reduction effect, it is assumed that the natural gas-combined cycle is the reference capacity type. As regards CO2 emissions, it is additionally assumed that about one-fifth of the non-sold electricity is from CO2-free sources. A sales margin of 5% is assumed, with respect to the valuation of the non-sold electricity. The most problematic estimate is the extra programme-cost. Metering cost can become expensive, depending on how (in)selective the programme is. Even with these modest assumptions, it appears to be rather attractive to introduce DSM programmes. With the current assumptions, the ratio between saved investment to extra marketing-cost plus lost sales margin minus reduced CO2 abatement cost amounts to approximately 11. It means that if there are alternative investment opportunities for the saved investment (305 mln E) that would have a pay-back time of less than 11 years, it would be attractive to carry out the DSM programme. It is highly probable to find alternatives that have a shorter pay-back time (outside electricity generation). 7. Epilogue An intriguing question is why has DSM not happened yet, if it seems to be attractive ? Various reasons have been already put forward in the previous sections. In summary the following issues cause delays or second thoughts about DSM:

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 Until the year 2001, wholesale prices were at structurally low-levels, even though a few hefty price peaks occurred in 2000.  As long as competing on price is the predominant approach, it is risky to introduce other elements (apart from bilateral contracts with very large customers in which net benefits can be assessed precisely). The position of TVO gives extra leverage to its large industrial owners for getting the best prices; for larger client groups, a pilot-approach may be attractive.  There is still a growing supply of innovative risk-handling methods and services in the Nordpool market area; this has also reduced the inclination to use mechanisms that transfer capacity shortage risks to the retail market.  The introduction of DSM takes time and needs to be customised for different client groups. Contracts about rebates in return for specified interruptible loads are only attractive for a small group of very large users: this can be a first step having a limited transaction cost as well as fairly certain and sizeable impacts. As a second step, there could be various standardised contracts for client groups: the contract could involve an energy scan and may involve extra metering cost. Finally, one could resort to a general introduction of time-of-day pricing.  Apart from the needed preparation time, the partial separation of distribution and generation, makes it complicated and unsure for market players, whether they get the part of the benefits they want (or at least the part they need to make it cost-effective). This is the reason why Demand-Side Bidding can be a very effective extension to the DSM portfolio. Also Energy Service Companies (ESCOs) are expected to make the market move, as soon as ESCOs themselves become better established in the Finnish market (and elsewhere in the Nordic market).  The recognition that the avoidance of CO2 emissions has really a value that is new to the sector.  The long history of (public) electricity-utilities, that were tuned to the provision of reliable and cheap electricity, which has bred attitudes that differ from the ones that a successful DSM programme requires.

As the period of capacity surplus in the Nordic electricity market seems to be over and higher wholesale prices can be anticipated, the willingness to introduce DSM and DSB will certainly increase as the benefits created by such instruments will grow accordingly. The Commission of European Communities announced the intention to submit a directive on DSM within the framework of the European ClimateChange Programme [17]. This would further enhance the introduction of DSM in the Nordic power markets. Interestingly though DSM is not just a matter of more efficient use of installed generation capacity, but promises to have benign environmental effects as well, thanks to its generic electricity-saving impact. The introduction of localised renewable energy options will probably also require new types of DSM. Given the dominant availability of (river)hydro and biomass in Finland, this aspect of DSM is

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presumably less urgent in Finland, with the exception of that for intelligent lowenergy buildings.

References [1] Ministry of Trade and Industry. Sa¨hko¨markkinoiden kehitystarpeet (the need for amendments in the electricity market). Helsinki, 2001. [2] Midttun A, editor. European energy industry business strategies. Elsevier Science, 2001. [3] Euroelectric. Business trends in the European power-industry—consequences of liberalisation. Ref. 2001-2760-0011, Brussels, 2001. [4] Nordel. Energy and power balances for the three-year period 2002–2004. 2001, web site. [5] ETSO press release 4-3-2002. [6] Ministry of Trade and Industry. Kansallinen Ilmastostrategia (National Climate Strategy), Helsinki, 2001. [7] Unger T, Andersson O, Ryde´n B, Wene CO. The Nordleden project—cross-border grid-distributed energy trade and common action among the Nordic countries to facilitate CO2 reductions. Final report, Chalmers University, 2000. [8] Electricity and district heating in 2000. Adato, Helsinki, 2001. [9] Statistics Finland, Energy Statistics 2000. Helsinki, 2001. [10] Electricity market authority, presentation at SEE conference, May 2001. [11] Kemppi H, Lehtila¨ A. Hiilidioksiveron taloudelliset vaikutukset (the economic impacts of a CO2 tax), VAT discussion report (forthcoming), Helsinki; 2002. [12] Electricity market authority. Pre tax price development of various user types since 1996, downloadable price time series dataset. [13] Eto J, Kito S, Shown L, Sonnenblick R. Where did the money go? The cost and performance of the largest commercial sector DSM programmes. Energy Journal 2000;21(2):23–49. [14] Hoff ThE. Using distributed resources to manage risks caused by demand uncertainty. The Energy Journal [Special issue distributed resources: toward a new paradigm of the electricity business]. 1997. pp. 63–83. [15] Thomas S, Adnot J, Pierluigi A, Irrek W, Lopes C, Nilsson L, et al. Completing the market for leastcost energy services. EU SAVE study, Final report+4 Annexes, Wuppertal Institut; 2000. [16] IEA-DSM Programme, web site: http://dsm.iea.org/, in particular Task VIII. [17] Commission of European Communities. Communication from the Commission on the implementation of the first phase of the European Climate-Change Programme, Brussels, 23-10-2001, COM (2001) 580. [18] Nordpool web site, http://www.nordpool.com/.