* Investors eye gas plants in Europe after buying assets in Britain
* Gas generator profits have eroded in Europe
* Bet on rising power prices, capacity mechanisms is risky
By Nina Chestney and Christoph Steitz
LONDON/FRANKFURT, Feb 18 (Reuters) - Investors keen on snapping up a gas power plant should keep their focus on Britain as deals in continental Europe could backfire more easily if bets on rising power prices and capacity gaps go against them.
Europe’s gas plants’ profits have taken a severe hit due to growing renewables capacity, low coal and carbon prices and stagnating energy demand in a weak economic environment.
Some opportunistic investors, such as Australian bank Macquarie and trading house Vitol, have started to buy these distressed assets, most notably in Britain, betting on a recovery of low power wholesale prices and capacity gaps that could increase their future value.
In Germany, Europe’s biggest energy consumer, power generators currently lose almost 15 euros per megawatt hour (MWh) for benchmark 2015 power derived from gas, while using hard coal yields a profit of nearly 13 euros per MWh.
This has forced 10 utilities, including E.ON, RWE , Centrica, GDF Suez and Verbund , to close or mothball at least 21 gigawatts (GW) of gas capacity over the past 20 months, roughly equivalent to Austria’s total electricity generation capacity.
Eager for reasonable returns amid low interest rates, investment funds and trading houses from Europe and Asia are eyeing acquisitions in continental Europe, but a greater share of renewables and larger excess capacity makes for a tougher market.
“The UK is a safe bet as the market is getting tighter and needs new capacity,” said Roland Vetter, head of research at investment firm CF Partners.
“On the Continent, you know oversupply won’t be eliminated quickly so you make two possible bets: that the Continent needs capacity markets one day and you then will be renumerated for having a plant available or that the EU carbon price goes up so gas becomes more profitable than coal,” he added.
Across Europe, gas plants are being nudged out of the power market by renewable energy sources, which take priority when being fed into the power grid over coal and gas.
It is also cheap to burn coal. European Union carbon prices are too low at under 7 euros ($9) a tonne to give utilities the incentive to switch fuel from coal to natural gas and are not forecast to jump considerably this decade.
This, along with tepid energy demand in Europe, has led to a 60 percent plunge in German wholesale power prices since 2008 to below 37 euros per MWh, pushing gas plants, some of which are state of the art in terms of efficiency, into loss.
Due to a massive surplus in generation capacity and the further growth of renewables, power prices are expected to remain depressed in much of Europe this year, according to Credit Suisse, except in Britain.
In contrast to Europe, capacity in Britain is expected to get tighter and gas plants will be needed to fill the gap.
Almost a fifth of Britain’s generating capacity - old nuclear and coal - will close this decade, yet power demand could double by 2050, the British government has said.
These conditions have made Britain the prime market for gas plant acquisitions. Macquarie has snapped up three gas-fired units in Britain from General Electric, EDF and DONG since late 2012.
Vitol also bought the 1,220 MW Immingham station from Phillips 66 last year. Both firms declined to comment on their acquisition strategies.
Meanwhile, Russian natural gas producer Gazprom has concentrated on Europe as it wants to extend its influence by supplying European plants with its own gas.
The firm has said it is looking at combined cycle gas turbine (CCGT) plants in several European markets where the outlook is “attractive”, without specifying which countries.
GDF Suez agreed to sell 50 percent of a 3,300 MW portfolio of thermal and renewable power generation assets in Portugal to Japan’s Marubeni Corp.
But buying loss-making plants in Europe is risky.
“There isn’t much turnaround for gas and power plants in Europe because there is a weak outlook for power demand and continued renewables deployment,” said Tom Tindall, director at research group IHS CERA.
IHS CERA has estimated that 110 GW of gas capacity - 60 percent of the European Union’s total capacity - is at risk of closure in the next three years.
Earlier this month, RWE said it would mothball a highly efficient CCGT plant in the Netherlands which cost 1.1 billion euros to build and had only started to produce power in 2012.
Many investors are hoping they will benefit from capacity markets, which pay operators to keep plants on standby to cover variable renewables’ supply.
“If you buy a CCGT plant in Europe you should hopefully get it for nearly free, then mothball it and hope one day you receive capacity mechanism payments to justify owning it,” said Roland Vetter, head of research at investment firm CF Partners.
Britain will start capacity auctions at the end of this year, in which generators will bid to provide capacity using existing and new plants at a price that lets them keep the plant running for a certain period of time.
They are set to earn substantial margins as the capacity payments will likely be above the fixed costs of a CCGT plant which range from 10 to 20 pounds per kilowatt per year, according to UK-based consultancy Timera Energy.
Elsewhere in Europe, capacity mechanisms are less developed. France plans to launch one by 2016 but details are still unclear; Italy plans one by 2017 and Germany is discussing the need for one.
Some of these payments might only cover plants’ operating costs and not necessarily result in big profits.
“The case for capacity markets is less clear on the Continent. They are being discussed, but their development is less urgent given the current overcapacity situation,” said David Stokes, director at Timera Energy.
$1 = 0.7307 euros Additional reporting by Henning Gloystein in London, editing by David Evans