THE NORDIC power market is experiencing its second consecutive winter with very low hydro power reservoirs. Generators and vertically integrated utilities are likely to benefit from the continued high prices. Unlike in the winter of 2002-2003, however, prices have not skyrocketed. The impact of the situation on the companies will mainly depend on the extent of their reliance on hydro generation and their hedging positions.

In the winter of 2002-2003, the reduction in hydro generation was in general more than offset by higher prices. The impact on earnings, however, was moderated by hedging positions where substantial portions of production had already been sold on the forward market. Generators and integrated utilities are expected to continue this strategy, which should have a moderating effect on the volatile market. The risk for electricity distributors of ending up short in supply in a high-price environment should be mitigated by volume-risk hedging arrangements.

Standard & Poor’s Ratings Services does not expect any immediate implications for credit ratings. Instead, companies will add to their financial headroom or accomplish financial recovery faster than expected.

The market participants are generally better prepared for high prices and volatility this winter than in 2002-2003. Unlike in 2002, hydro levels in 2003 have been low throughout the year, although the capacity gap is gradually decreasing. The market has behaved relatively calmly so far and the nervous pricing behaviour seen in 2002-2003 has not been repeated. Forward prices suggest that the market is less concerned about short-term supply now than at the same time in 2002, but that a recovery to more normal levels is expected to take longer. In addition, as a consequence of the relatively mild winter so far, the monthly average spot price for December 2003 was lower than prices in 2002 for the first time. The risk of another price shock appears to have reduced.

The Nordic power exchange NordPool ASA has also improved its capacity and procedures, and exchange members are better prepared with negotiated credit lines to cover security requirements. This should reduce, but not eliminate, the risk of liquidity shortages and counterparty failures. Market liquidity will remain essential to prevent severe market disruptions. Trading volumes on the financial market decreased significantly in 2003 compared with 2002, which may be somewhat problematic from a market efficiency perspective. Trading volumes could pick up when the underlying fundamentals settle. The departure of US-based trading companies has likely harmed liquidity even in the medium to long-term, however.

The constrained supply situation in winter 2002-2003 never developed into a shortage situation. This, however, is no guarantee that there will be no shortage in 2003-2004. The debate over security of supply is intensifying. In general, there is a lack of clear incentives for generators to invest in new capacity.

On the other hand, the 18 December 2003 decision by the shareholders of Teollisuuden Voima Oy, some of the largest Finnish industrial companies, to invest in a fifth Finnish nuclear reactor, illustrates that incentives to expand capacity have increased on the demand side. Several other projects are in the advanced decision stages.

The losers in the current situation are the Nordic electricity end-users. They have to pay more for a commodity that historically has cost less than in most of western Europe. Even if prices reduce in the medium term, assuming a normalisation of hydro supplies, they are unlikely to fall to historically low levels. This is due to tighter capacity balances and increased focus on profitability and risk cover rather than volumes among suppliers. Average generation costs are higher, and risk premiums are included to a greater extent in current prices than in the past. As a consequence, end-users have to adapt to high price levels. This could have an impact on future demand growth.

Reservoir levels still low

There are important differences between 2002-2003 and 2003-2004. The rundown of reservoirs in 2002 was caused by an exceptionally dry and cold autumn in combination with high hydro generation levels in the same period. The winter also brought unusually dry and cold weather. The low reservoir levels during 2003 were to a great extent caused by the low initial values at the beginning of the year. Whether the winter of 2003-2004 will be as dry and cold as the previous year remains to be seen, but it cannot be ruled out. Up until year-end 2003, however, the winter was significantly milder than in 2002. This suggests that the risk of higher-than-normal demand, as occurred in winter 2002-2003, has now reduced.

Hydro reservoir levels in 2003 were lower than in 2002 until the very end of the year. Only in early December did the 2003 levels become higher than in 2002. The level remains significantly below the median value, resulting in a deficit of about 18TWh.

Higher prices in 2003

Prices throughout 2003 were higher than historical levels. The 2003 spot prices are about 2.5-3.0 times the average for 1997-2000. Excluding December 2003, when the monthly average price was US$3.77/MWh compared with the extremely high US$8.04/MWh for the same period in 2002, prices in 2003 have been higher throughout the year.

Forward prices have also remained high throughout the year. Short-term forward prices (one to four months ahead) were lower in early December 2003 than at the same time in 2002. The more extreme prices in 2002 appeared in late November and December, and continued well into 2003. Longer-term forward prices, however, are higher. This supports the supposition that the market expects a recovery to normal levels to take some time, although there is less concern about short-term supply.

Prices of about US$32.51–36.94/MWh now appear to be the expected normal longer-term level, which is above the historical average.

It was not only the poor hydro generation situation that created high prices during winter 2002-2003. Unexpected outages and prolonged maintenance works on Swedish nuclear generation have taken place, putting further pressure on the supply balance. Furthermore, coal prices have increased, pushing up the generation cost for marginal electricity supply from Danish coal-fired generation. There has also been significant dependence on power imports from continental Europe, where prices have been relatively high in 2003, partly for the same reasons as in the Nordic region.

Low price elasticity

Price movements in the Nordic Power Exchange are driven by supply and demand dynamics. At times of low hydro supply, the resulting electricity shortfall is replaced by higher-cost generation. Many generators also lack incentives to add new capacity to the market, because they generally benefit from higher price levels.

The current price levels could harm long-term demand. Price elasticity among electricity consumers in the Nordic region has traditionally been fairly low, as was evident in 2002-2003. Long-term demand growth in the Nordic region is expected to be fairly stable at 1.0–1.5% per year. This is moderate for mature economies, and is comparable to countries such as Germany, the UK and France.

With the exception of Denmark, electricity per capita consumption in the region is among the highest in the world. There is a lot of energy-intensive industry and high demand for electrical appliances and heating in the residential sector. At the same time, again excluding Denmark, electricity prices are comparatively low.

2002-2003 market disruptions limited

Despite the sharp rise in, and increased volatility of, electricity prices during winter 2002-2003, only three market participants ended their activities on NordPool due to financial distress. There were some fears that the situation would result in a greater number of defaults owing to bankruptcy or liquidation among participants, which would lead to significant market disruption. This situation, however, never arose.

As a clearing institute, NordPool is also exposed to potential counterparty failures. Protection against such failures should be reflected in the company’s equity base.

Live and learn

Winter 2002-2003 provided a learning experience for many market participants. Several factors are also relevant to winter 2003-2004.

New capacity is offset by increased demand and declines in imports, but incentives for generation investment are weak.

According to Nordel, the organisation representing Nordic transmission system operators (TSOs), total thermal power production capacity in the region in 2003-2004 is expected to increase by 1010MW. This is largely offset by an expected 390MW increase in consumption and 400MW less imported from Germany. Overall, imports for 2003-2004 are expected to fall to 1.4TWh from 5.6TWh in 2002-2003. Even so, incentives to add more capacity remain fairly limited.

Obstacles to investment include:

• Hydro power-induced volatility of power prices,

• National environmental and taxation policies that restrict ability to expand fossil-fuel generation and hydro power,

• Painful experiences during the overcapacity situation in 1997-2000,

• Uncertainty regarding the availability of, and terms for, gas supplies,

• Utilities’ weakened financial profiles, which force companies to prioritise investments,

• Lack of interest in traditional risk mitigants, such as long-term supply contracts, among off-takers.

Demand remains difficult to predict and price elasticity proved to be fairly low in winter 2002-2003. In 2003-2004, consumers are likely to be better prepared for a potential price shock. Over time, flexibility on the demand side is expected to increase further as consumers adapt to the higher-price environment.

Peak demand in 2002-2003 was mainly handled through increased imports. The power balance relies to a great extent on undisrupted import capacity and the availability of generation assets.

Nordel estimates that there are sufficient reserve margins in most areas even in a worst-case winter scenario. The exception is the southern part of Norway, where rationing was actually considered at some points during winter 2002-2003.

Importance of market liquidity

Maintained market liquidity is important to avoid adverse pricing behaviour. Lack of trading volume on the electricity spot exchange was generally not considered to be the driver of the very high prices in 2002-2003. The situation on the financial contracts market was, however, more turbulent.

Trading volumes in the spot market in 2003 were relatively unchanged, but volumes in financial markets are much lower than in 2002. This is mainly a consequence of the memories of winter 2002-2003.

Volumes in the electricity spot market in the first eight months of 2003 were slightly higher than in the same period in 2002. Until 2003, NordPool’s trading volumes had grown every year since it was set up in 1991.

In the first eight months of 2003, however, volumes on NordPool’s financial market decreased by almost 40% compared with 2002. Clearing volumes also fell dramatically, by 34%. The reduced liquidity seen in 2003 is somewhat problematic from a market efficiency perspective. Trading volumes may eventually pick up if underlying fundamentals settle and the marketplace matures further.

Improved procedures by NordPool

The significant increase in financial security requirements by NordPool, which was a consequence of the sharp increase in electricity prices, caught many of the market participants by surprise in 2002-2003. In many cases, increased credit lines with banks had to be negotiated under considerable time pressure.

NordPool has now modified its requirement regime. Balance checks for marginal calls are made more frequently than in the past and should result in more dynamic management, although amounts can still be high. In addition, market participants should be better prepared this winter with negotiated bank lines.

Increased reserve and transmission capacity among TSOs

Nordic TSOs have prepared for the winter by buying additional reserve capacity in order to avoid a shortage situation. In addition, TSOs are working to improve import capacity in existing cross-border interconnector cables or to manage existing bottlenecks in the Nordic grid more effectively. Further harmonisation of congestion management methods among the Nordic countries could gradually increase cross-border transmission capacity.

Import capacity to Norway remains the most critical bottleneck in the Nordic system. No major cross-border grid investments are currently planned for.

Positive to neutral effects

Generators and vertically integrated companies with hydro generation assets will be affected by lower hydro supply, which leads to lower production volumes. The loss of production has generally been more than compensated for by the increase in prices. The ultimate impact will also be strongly influenced by the respective company’s hedging strategy. The main risk is to end up short in supply in a high-price environment. Volume risk is the most significant factor because price risk is normally secured when the contract is signed. Volume risk is generally also taken into account when setting the price, although a full hedge is difficult to achieve. Any excess generation not used for contracted sales to end-users is sold on the spot market when prices exceed the marginal costs.

Danish generators such Elsam A/S and ENERGI E2 A/S, which depend on higher-priced thermal generation, have benefited from the high prices in 2002-2003. Export of Danish production to other Nordic countries has been high. Graninge AB, which is highly dependent on hydro production, has suffered from a significant decrease in production compared with a normal year. This, however, has been more than offset by the higher prices on the spot market.

Consolidation continues

Recent developments are likely to fuel the ongoing consolidation of the Nordic power industry, particularly on the supply side. A significant part of the retail market is still served by municipally owned supply companies. Many of these companies are likely to have been financially affected by the volatile prices, making owners reassess their commitment to the business.

It is likely that consolidation will continue to be driven by the incumbent major players. In the autumn of 2003, Sydkraft AB acquired Sweden’s fourth-largest utility, Graninge. Sydkraft will also execute the Nordic strategy of its parent company and 55% owner E.ON. Fortum Oyj has expressed growth ambitions, and might be able to exploit its newly acquired holdings in Norwegian utilities to expand beyond its current Finnish and Swedish core markets. Statkraft SF has ambitions to expand in Norway and northern Europe. In Denmark, Elsam, one of the major electricity generators, placed a bid to acquire NESA A/S, a major electricity distribution company. NESA is also part owner of the other major Danish electricity producer, E2.