By Henry Edwardes-Evans & Alex Froley

December 3, 2009 - Two years ago European forward power prices were running consistently at between €60-70/MWh. Nobody foresaw that within 12 months those prices would have gone on an unprecedented bull run up to €80-100/MWh before crashing to €40-50/MWh.

Indeed the consensus was that prices would stabilize at or above new entrant levels of €60/MWh. It was during this rosy period of high prices and optimistic forecasts that a large number of gas, coal and renewable power projects moved through permitting to advanced development status.

Two years on and the benchmark German year ahead baseload power price is languishing below €/MWh. How has this price and demand destruction affected utility investment plans? With the evaporation of economic and physical demand drivers, what is giving impetus to new investment today?

With analysis of Platts' power market reports and new construction data, this feature explores the strategic choices and risks facing European utilities at a time of financial hardship, and identifies diversity in gas supply as a key component in Europe's efforts to move from high to low carbon intensity.

 Timing the recovery

The timing of demand and price recovery is weighing heavily on the power sector. Nine month 2009 sales and revenue figures from the major utilities reflect industrial demand decline, offset only partially by resilient residential demand.

A 39% boost to domestic resources would be welcomed by a continent still questioning the reliability of gas in the wake of the major Russia/Ukraine gas transport dispute at the start of the year. While demand decline has slowed as the year has progressed, hopes that the trend might reverse this year have ebbed away.

At the 14th International Gas and Electricity Summit in Paris in October senior European gas industry figures were generally cautious.

Power and gas consumption in Germany is down 7% year on year -- and 14% in the industrial sector. Spanish power demand is set to drop by 4-5% for full year 2009, according to REE chief executive Luis Atienza. "Three months ago we thought we were going into positive territory towards the end of the year, now we see that's not the case," he said. REE expects demand to remain flat in 2010.

Germany’s benchmark Cal 10 base contract at €45/MWh on November 25 has been falling steadily since October 21, when a brief rally saw it rise above €49. The long-term new entrant price of €60-65/MWh is a distant prospect.

More generally, continental European Cals are more than €30/MWh down year-on-year as the contracts struggle to regain ground lost over the last 16 months.

The recent exception has been France, where nuclear availability issues temporarily inflated forward prices, but the brief volatility was short-lived and the French Cal has itself dipped below €50. (See chart: Platts Year Ahead Base Power Assessment (€/MWh)).

There is a fragile consensus that demand recovery in power and gas markets will take around two years. Gas price recovery may take longer, for reasons explored later in this article.

With regard to generating capacity margins in the longer term, the UK is seen as a European exception when it comes to judging demand recovery because, whatever happens, supply is heading for a cliff in five to six years time when non-retrofit coal plant is forced to close.

The UK is also uniquely disadvantaged by its choice of nuclear technology, so extensions are highly unlikely.

On the continent the supply-demand balance is less certain because a much higher proportion of coal plant has been retrofitted and nuclear units have the potential of extended lifetimes.