The group, Europe’s biggest polluter thanks to its extensive
use of lignite, or brown coal, said quarterly earnings before
interest, tax, depreciation and amortisation (EBITDA) fell 3
percent to 3.04 billion euros ($3.95 billion), hit by sluggish
energy prices and falling margins in power generation.

That was just ahead of analysts’ average forecast of 3.02
billion euros, and RWE confirmed its expectation for EBITDA of
about 9 billion euros this year.

Gas contracts have been a major problem for European
utilities which are being squeezed as they buy gas under
long-term deals concluded with companies such as Gazprom
and Statoil when prices were firmer, while
having to sell it to customers at lower prices.

Following the renegotiation of some gas contracts, RWE’s
Supply & Trading unit narrowed its operating loss to 47 million
euros in the first quarter, compared with 220 million last year.

The group confirmed it still expects to strike a deal with
Gazprom by mid-year, which Chief Financial Officer Bernhard
Guenther said would result in a “significant” financial effect
for the group.

“We forecast a 300 million euros compensation payment,” said
RBC Capital Markets analyst John Musk.

RWE declined to put a figure on the expected benefit.

Along with its peers E.ON and EnBW, RWE
is suffering from falling wholesale power prices in Europe, its
core market, due to weaker appetite for energy on the
recession-hit continent and energy savings measures.

The International Energy Agency (IEA) expects primary energy
demand in the European Union to decline by 2 percent in the
2010-2015 period, compared with a 10 percent rise globally.

Prices have also come under pressure from the massive
expansion of renewable energy in Germany, as energy from solar
and wind sources takes priority in being fed into the
electricity grid, reducing the hours gas plants can run and
hurting the profitability of conventional power plants.

To streamline their businesses, German utilities have been
shedding non-core assets worth billions of euros. This includes
RWE’s oil and gas exploration and production unit DEA
, which it said was not expected to be sold this year.

RWE has felt relatively little impact from Germany’s
decision to completely pull out of nuclear power by 2022, as
only 13.5 percent of its power comes from the source. That
compares with more than a fifth at its main peer E.ON.

RWE’s exposure to profitable lignite, or brown coal, has
boosted its earnings vis-a-vis E.ON. RWE gets more than a third
of its power from the highly polluting material, compared with
E.ON’s 6 percent.

Guenther said RWE emitted 2.7 percent less CO2 in the first
quarter, partly due to the closure of old brown coal generation
units at the end of 2012. But he declined to forecast CO2 output
for full 2013.

At 1030 GMT, RWE’s shares were little changed at 27.525
euros.

($1 = 0.7705 euros)

(Editing by Harro ten Wolde and Stephen Coates; Editing by Mark
Potter)

East Germany was a huge user of brown coal, or lignite, and
Germany remains the world’s biggest producer, but its use poses
a problem for Berlin’s environmental plans.

Limiting brown coal use is politically difficult, however,
with 20,000 mining and utilities jobs involved and any move that
could raise already high energy bills for consumers a risky
gambit ahead of federal elections in September.

Coal also remains important to profits at utilities such as
RWE and the German arm of Sweden’s Vattenfall
.

“Lignite load factors have remained high and gross margins
held up better than for other fuels,” JP Morgan analyst Vincent
de Blic said.

RWE mines its own lignite and relied on it for 36 percent of
its electricity production last year.

Coal helped RWE’s power generation unit to a 14.1 percent
rise in profits and prompted the company to add more as it
started output at a 2.1 gigawatt twin-unit lignite-powered plant
in Neurath near Cologne.

Despite Germany’s green energy drive, which subsidises
renewable wind and solar energy and aims to drop nuclear power,
the country mined 5.1 percent more brown coal in 2012, industry
association Debriv data showed.

Brown coal-fired plants also produced 6 percent more power,
the 159 billion kilowatt hours (kWh) accounting for 25.7 percent
of Germany’s power production, industry figures showed.

Germany needs nuclear, coal or gas for so-called base power
to ensure steady supply alongside volatile wind and solar
energy.

And it is coal that is winning out because German utilities
can turn a profit using it to generate electricity, something
they are failing to do with gas.

“Gas-fired capacity is being crowded out by wind and solar
and, paradoxically, by coal-fired capacity,” E.ON Chief
Executive Johannes Teyssen said last month.

E.ON, Germany’s biggest utility, is less exposed to coal
than RWE, however, using lignite to fire just 6 percent of its
generation last year. The German arm of Vattenfall relied on it
for 31 percent of its power.

DARK OR SPARK?

While brown coal mining grows, Germany by 2018 plans to
phase out mining hard black coal, which provides around 20
percent of the country’s power using mostly imported supplies.

Power generators currently can earn more than 10 euros per
MWh for benchmark 2014 power derived from hard coal
while using gas means making a loss of almost 14 euros per MWh
.

Using cheaper lignite is even more profitable at more than
20 euros per MWh, according to Morgan Stanley and JP Morgan
analysts.

Current low prices for permits which utilities and
manufacturers must purchase to offset their carbon output is
also buying “dirty” utilities more time.

Yet Germany’s environmental targets will eventually require
it to rein in brown coal – which has a CO2 intensity of 1,153
grams per kWh versus 428 grams for natural gas, according to
figures from the OekoInstitut, Germany’s institute of applied
ecology.

RWE’s Neurath and Niederaussem lignite power stations are
the second and third largest CO2-emitting installations in the
European Union.

While Germany’s carbon output held steady in 2012 helped by
improved energy efficiency, its broader emissions (of gases
monitored under the Kyoto Protocol) rose 1.6 percent partly due
to pollution from brown coal.

Analysts say one possibility is that Germany might introduce
a tax aimed at ensuring those cashing in on lignite help fund
the country’s 550 billion euro ($715 billion) shift to low
carbon energy.

“The greatest risk following this year’s elections in
Germany could be an increase in the nuclear fuel tax and a new
tax on lignite,” said Kepler Capital Markets analyst Ingo
Becker, adding such a move would likely hit the share prices of
utilities such as RWE.

($1 = 0.7689 euros)

(Editing by Jason Neely)

Trading volumes dropped to 8,534 terawatt hours (TWh) in
2012 in France, Germany, Italy, the Netherlands, Spain, Britain
and the Nordic region from 9,645 TWh in 2011, according to
estimates in a Prospex study due to be published on April 29.

The decline was due partly to the growth of renewable power
output, which can swamp the market with midday solar supply, for
example. This evens out previously volatile within-day prices
and reduces the potential for shortages, which makes hedging and
speculative activities less necessary.

The study also blamed uncertainty around new EU regulations
for undermining market confidence. A partial withdrawal of banks
and utilities from energy trading has also cut into volumes.

As for 2013, Prospex said that confidence in the market was
in a delicate state that made estimates difficult.

“It is too soon to be sure which way the market will go this
time,” Ben Tait, the UK-based firm’s director, said.

If top utilities and banks further reduce their activities,
other operators might also cut down on involvement.

On the other hand, if the market overcomes the current
turbulence, players may decide it’s safe to return, which is
what happened following previous trading crises, including after
the 2009 global financial downturn and after the collapse of
trader Enron in 2004.

“The end of this year or the beginning of 2014 should be a
better time to draw longer-term conclusions,” Tait said.

The depressed economic environment in the euro zone already
reduced volumes in 2011 by 12 percent from their all-time high
in 2010 of 10,925 TWh.

Trading volumes in 2012 in the over-the-counter (OTC)
market, which has been forming since 1999, fell by 18 percent in
2012. It maintained a share of 68 percent of all trading volume,
a figure that has been roughly consistent for years.

On exchanges, the trend in power trading volumes differed
between futures, which fell 6 percent, and spot business, which
increased by 14 percent, Prospex noted.

Germany and the Nordic countries kept their prominence as
the major trading centres due to easy trading systems, the
number of players and good interconnection capacity.

In Germany’s centrally located and liquid market, the
calendar-year power contract is the benchmark for the continent
as a whole, used as a proxy by neighbouring countries.

The German market trades 7.1 times its national consumption
of electricity, which is called the churn rate. The rate in
Nordic countries is 5.0 times, while the average of the major
markets is 3.4 times.

Major utility players in the sector include France’s EDF
and Germany’s E.ON and RWE, driven
by their need to protect commercial positions and hedge output.

Prospex noted that while the amount of OTC trades that were
financially cleared rose by 4 percentage points to 23 percent of
the total in 2012, this was down from a rate of 30 percent in
2008.

“Plainly many European power traders still prefer straight
bilateral deals without any support from exchanges or clearing
service providers,” it said, adding the tendency was strongest
in Britain, where 81 percent of OTC trades were not cleared.

The Federal Network Agency said on Thursday that talks were
underway with utility E.ON on how to keep its two unprofitable
blocks in Bavaria state online, as the need to maintain grid
stability makes their further operation a public issue.

“There are talks between us, E.ON and grid company TenneT
about the possible inclusion of the Irsching 4 and 5 generation
units into reserve status,” said a spokeswoman for the
Bonn-based Federal Network Agency.

“There has not been a conclusion as yet,” she added.

E.ON has said that weak demand and low wholesale
prices could force it to mothball the modern gas-fired power
blocks Irsching 4 and 5 unless they receive payments in return
for offering reserve power functions.

The case has a political dimension as after Germany’s
decision to pull out of nuclear faster and to hold on to a
subsidy-driven green energy expansion, the energy system is
turned upside down, causing margin pressure for utilities and
posing supply risks.

Grid firm TenneT is charged with maintaining power supply in
industry-heavy Bavaria and reports to the regulator, which
supervises the arrangements.

Both an E.ON spokesman and a TenneT spokeswoman declined to
comment on the issue on Thursday.

E.ON has threatened to apply for closure of a number of
plants due to a collapse of achievable power prices for its
output and relatively high buying-in gas costs, which are linked
to the price of oil.[D:nL5N0B08GI]

Also, green power supply takes precedence on transmission
grids. This cuts minimum running hours needed to justify returns
for some conventional power stations conceived to run 24-hours.

E.ON has put necessary payments for three year-old Irsching
5 at 100 million euros ($130 million) a year. Under energy laws,
it is not allowed to unilaterally go ahead and shut the plant.

TALKS FOCUS ON MONEY

The regulator already has TenneT on board, sources close to
the talks said. It not only agrees that block 5 of 846 MW is
needed locally to guarantee grid stability, but that this also
extends to block 4 of 550 megawatts (MW) capacity, which started
in 2011.

A huge E.ON nuclear reactor nearby at Grafenrheinfeld, is
slated to shut in 2015 under the nuclear exit law.

The current talks at the regulator focus on modalities of
the payments which E.ON would receive, as this determines how
much will have to be paid out by TenneT and recovered via a
charge borne by customers, the spokeswoman said.

Plants in reserve are paid just to stay open but are told
that the plant must not run commercially for five years.

An alternative, redispatch, would allow the operator to
offer the output commercially but reap higher payments if there
is proof that it was needed to ensure grid stability.

Irsching 3, an older gas-fired plant of 415 MW is already
assigned to so-called cold reserve for winter months.

E.ON owns the Irsching plants except for block 5, where it
has a 50.2 percent stake and shares the remainder with three
German city utilities, of Frankfurt, Nuremberg and Darmstadt.
($1 = 0.7668 euros)

(Editing by William Hardy)

“We will be taking our European business further because
energy markets are globalising,” Klaus Schaefer, head of the
unit, told a briefing on Wednesday at the company’s Duesseldorf
headquarters.

“We will be trading out of Chicago by year-end and branching
out into more Asian coal and liquefied natural gas (LNG).”

E.ON has for the past 18 months been pursuing the merger of
its former Ruhrgas subsidiary with energy trading into one
division as part of its efforts to streamline activities and cut
costs. The combined business will become operational on May 2.

Schaefer said trading prospects in the United States and
Canada had improved since the shale gas glut, which has pushed
more U.S. coal exports into the world market. U.S. gas exports
may start to flow on a large scale from around 2017, he said.

“We wouldn’t want to miss that story,” said Gareth Griffith,
chief commercial officer of E.ON Merchant Trading.

These efforts would tie in with E.ON’s globally growing LNG
landing and gasification terminals, which in Europe include
activities in the Netherlands, Italy and Spain.

The European LNG market would be “difficult in the next few
years”, but potentially improving dramatically later this
decade, Schaefer said.

Also, increasing renewable energy volumes within the E.ON
U.S. portfolio needed managing from inside the country.

E.ON said in February it was hiring traders in the United
States and Schaefer put the likely number of hires at five.

E.ON Global Commodities (EGC) – which includes the Merchant
Trading operation – has named Ben Pratt as managing director in
Chicago. U.S. native Pratt joins from Castleton Commodities
International for the fourth quarter 2013 start.

As for the Singapore office, there would be more trade
origination sought to respond to growing Chinese and Indian
energy demand, Schaefer said.

There are also gaps in the European traded power and gas
market left by banks which began retreating last year as they
decided to discontinue operations ahead of tighter regulation.

E.ON would step into some of these vacuums, said Christopher
Delbrueck, chief financial officer of EGC.

The E.ON group’s power trade volumes in 2012 fell 23.5
percent year-on-year to 1.4 billion kilowatt hours and those of
gas declined 1 percent to 2.5 billion kWh, its financial report
for the year showed.

Generous subsidies have boosted renewable electricity
generation, and created a German green power glut. But Germans
themselves do not see lower prices, which are restricted to the
wholesale market – in fact the opposite. Instead it is their
neighbours whose bills benefit thanks to cheap imports from
Germany.

International Energy Agency data for 2012 put household
electricity in Germany at $352 a megawatt hour, Dutch
electricity at $238, Switzerland at $222 and France at $187.

When Chancellor Angela Merkel’s government accelerated the
nuclear exit in 2011 and set the country on a course to switch
to renewable energy, some experts warned that there would be
power shortages as a result.

But power trade statistics from the biggest electricity
market in Europe not only dispel this notion, they also show
that German households subsidise power supplies elsewhere.

“The Germans have taken on a disproportionate share of the
high cost of renewables via the support payments,” said Kornelis
Blok, director of science at Dutch consultancy Ecofys.

“These leave a burden on the household price. So who is in
fact paying for cheap Dutch power? It is the Germans.”

Despite its nuclear exit, Germany remained a large exporter
of electricity in 2012, especially to the Central West Europe
(CWE) market region of France, Benelux and Germany and into the
Alpine states of Switzerland and Austria.

Germany exported 67.3 billion kilowatt hours (kWh) of power
last year compared with 42.8 billion kWh of imports, data issued
by the federal statistics office and the industry statistics
group AGEB show, although they say that this includes transits
and non-commercially traded volumes arising from grid balancing.

Wholesale power prices in Europe’s biggest economy have
dropped by over 32 percent in the past two years, pulled down
largely by a flood of subsidised new solar power generation that
has not been equalled in neighbouring markets.

German solar power producers added 31 percent more capacity
in 2012 to arrive at 32.4 gigawatt of capacity at the end of the
year.

“German power prices have decoupled from other central
European markets, such as France, the Netherlands or Belgium,
likely on the back of strong growth in solar capacity,” Bank of
America Merrill Lynch said in a research note.

The equivalent French price has dropped around 27 percent,
while Dutch prices are down less than 20 percent, according to
Reuters data (see chart).

GERMAN HOUSEHOLDS BILLS RISE

Germany’s cheap wholesale power prices make them attractive
for exports. The German export figure is equivalent to what
eight conventional power plants generate in a year.

The Netherlands were the biggest recipient of German
electricity, with 22.6 billion kWh (2.5 power stations),
followed by Austria’s 15.1 billion kWh (2 power stations), and
Switzerland’s 12.7 billion kWh which equate to the annual output
of 1.5 large power stations.

The rest of German electricity exports largely went to
France, which also supplied large amounts of power back to
Germany.

German retail power customers have already seen their bills
rise by over 12 percent since the beginning of the year, with
the share of renewable subsidies and other state charges in
their total bill now at 50 percent.

Merrill says that the trend of decoupled and lower German
prices is not seen coming to an end as it expects more renewable
capacity to be added to the system until the laws are changed.

“We see a possibility of further decoupling,” the bank said.
($1 = 0.7635 euros)

(Editing by William Hardy)

Gazprom, which has a 10.52 percent stake in VNG, inched
closer to its target of better access to lucrative nearby
European markets when it bought small retailer Envacom in late
2011 after failing to link up with RWE.

Last November, the Russian energy giant also widened its
reach in the EU with an asset swap deal with BASF over three
wholesale gas trading units and storage activities formerly
shared with the chemicals group.

A year ago, goldgas was bought and restructured by private
equity firm bluO, which is now selling it.

“VNG is to buy goldgas to make its core business complete
along the value chain of exploration, production, trading,
transport and storage,” the Leipzig-based company said in a
statement.

The financial details of the transaction were not disclosed.

The deal is subject to cartel office approval, and a
decision is expected in the coming weeks, VNG said.

Goldgas, which comprises the brands goldgas and goldstrom,
has 130,000 customers across Germany and Austria. It supplies
households, housing associations and enterprises with power and
gas.

VNG evolved from communist Germany’s gas company and is a
long-term partner of Gazprom, among other gas
suppliers.

It has stakes in six regional and local distributors
(Stadtwerke) in Germany and neighbouring Europe. Outside
Germany, where it is in the top group of gas firms with E.ON
Ruhrgas and Wingas, it also sells to
Italy, Poland, Luxembourg, the Czech Republic, Slovakia, Austria
and France.

Unlisted VNG group had total sales of 9.9 billion euros in
2012, representing a 21 percent year-on-year rise, and a net
profit of 103 million euros after a net loss of 211 million
euros 2011.

VNG is part-owned by unlisted north-west German regional
utility EWE, in which Germany’s No.3 utility EnBW has
a 26 percent stake. EWE’s stake amounts to 47.90 percent.

Other shareholders in VNG include a group of local utilities
called VNG Verwaltungs- und Beteiligungsgesellschaft of Erfurt
(25.79 percent), Wintershall Holding GmbH (15.79
percent), and Gazprom Germania (10.52 percent).

VNG in January secured a 1 billion euro credit line from 12
banks for planned investments.

In a separate move, VNG is planning to sell its gas
transmission system operator Ontras, sources said earlier this
month.
($1 = 0.7654 euros)

(Editing by Alison Birrane)

The move is more bad news for gas-fired generation, once
feted for its relatively low carbon dioxide emissions but now
struggling in a market heavily distorted by subsidies for
renewables plants. Other utilities face the same problem.

Renewable power receives priority grid access and its
operators are paid above-market subsidies, which has rapidly
eroded profit margins for thermal power stations.

The 510 megawatts (MW) Robert Frank unit in Landesbergen,
Lower Saxony will shut as soon as agreements on the job losses
are completed with trade unions, the company said in a
statement.

“The current market situation does not allow us to run older
gas-fired power plants economically, let alone invest in new
capacity,” said Asbjoern Grundt, executive vice president for
market operations and IT.

State-owned Statkraft just over a year ago shut a similar
430 MW plant at Emden, citing the dismal market conditions for
gas generation arising from overcapacity, the fast expansion of
competing renewable energy, low usage and low wholesale power
prices.

On Wednesday, E.ON repeated it would wrap up by
the end of this month discussion on whether or not to mothball
Irsching 5, a very modern power station in Bavaria which only
opened three years ago.

Statkraft’s managing director for Germany, Juergen
Tschzoppe, said the 40-year-old Robert Frank needed to shut
because even its far more modern plants, Knapsack and Herdecke,
were working below their potential.

“Robert Frank in theory would be a cheap back-up compared
with other technologies but there is no state compensation for
this function,” he said.

German grid firms must declare a plant system-relevant –
meaning it is needed for grid stability, for possible state
payments to be approved for the operator, but this did not apply
to Robert Frank, Statkraft said.

Plants threatened by closure may be too close to industrial
consumers to risk shutting them and risking a system black-out,
operators have said. The energy regulator therefore can rule
that state fees are paid to keep them online.

In theory, gas-fired plants would be an ideal complement as
they can be quickly activated if a lack of wind or sunshine
curbs green power supply.

Statkraft said last month it would bring a brand new
430-megawatt (MW) gas-to-power plant near Cologne on line by
mid-year, but worried about its profitability.

Power prices, now at 8-year lows, had been twice as high
five years ago, when the decision to build it was made.

Gas-fired units also suffer versus coal-fired rivals because
coal prices are low, as are those for carbon certificates which
electricity generators must hold.

Utilities are calling on regional state leaders and the
federal government to come up with ways to keep plants open.

But free-market liberal Economy Minister Philipp Roesler
said if even the problem of over-subsidising green energy was
now recognised, it would not make sense to throw even more
support at conventional power.

“That could not be the sole solution for a future market
design in Germany,” he told parliament on Thursday.

(Additional reporting by Markus Wacket, editing by William
Hardy)

Power demand in Germany, Europe’s biggest economy and energy
market, fell 1.4 percent in 2012 to 552.3 billion kilowatt hours
(kWh), according to industry data.

As a result, German wholesale electricity prices have
dropped over 30 percent in the past two years, while gas prices,
linked to the oil market, have remained relatively high,
undermining the profitability of gas-fired power stations.

Because of the margin pressure, E.ON has said it will review
selected European power stations with a total capacity of 11,000
megawatts (MW) for their productivity, including its $500
million, highly modern Irsching 5 gas-fuelled plant in southern
Germany, only opened three years ago.

By way of comparison, Germany’s daily power demand is
usually around 80,000 MW.

“If the profitability of this plant is not restored, we will
have to close it,” E.ON Chief Executive Johannes Teyssen said on
Wednesday.

“We will take a decision at the end of this month,” he
added.

Teyssen said he expected another overall decline in European
power and gas demand for 2013 as the region’s economy slump
curbs industrial activity.

“Power demand in northern Europe could be relatively stable
and gas demand fall slightly. In southern Europe, demand (for
both) should fall significantly.”

RENEWABLES UNDERMINE PROFITS

In Germany, furthermore, E.ON said the government’s decision
to phase out nuclear energy and accelerate the expansion of
green power had curbed profits.

Renewable power generation, such as wind or solar, receives
priority grid access, and its generators are paid above-market
subsidies, eroding profit margins for thermal power stations.

“It cannot be that year after year more money is spent on
renewables while operators are left with the cost of
system-relevant power stations and are forced to continue
operating under uneconomic conditions,” Teyssen said.

E.ON in 2012 sold a stable 181.4 billion kilowatt hours of
power in Germany, its annual report showed, which was a quarter
of its total group power sales. In other EU countries, its sales
declined 7 percent year-on-year to 145.9 billion kWh.

Wholesale gas sales placed in the German market by the E.ON
optimisation and trading subsidiary rose to 438 billion kWh last
year, up 11 percent from 394.4 kWh a year earlier.

E.ON cited weather and new customer acquisitions for its
relative success in Germany.

As a result of its power generation, E.ON said its carbon
emissions in Europe last year totalled 89 million tonnes of CO2,
up slightly from 2011.

Teyssen said that one of the new trade focus areas would be
liquefied natural gas (LNG), where there were international
arbitrage possibilities.

LNG prices in Asia, Europe and North America vary strongly,
with Asia typically paying around $17 per million British
thermal units (mmBtu), Europe slightly above $10 and North
America only around $3.50 per mmBtu.

E.ON’s gas subsidiary, Ruhrgas, is to merge with its trading
division in spring.

E.ON also said that it would exploit its huge global coal
trading activities.

(Editing by Henning Gloystein and Jane Baird)

The European Commission separately said it would investigate
the exemptions, which were granted to big companies in sectors
such as metals, chemicals, glass, cement and building materials.

The Duesseldorf district court (OLG) said it had found that
Germany’s energy law failed to provide a legal basis for the
exemptions, which began in 2011.

“The…OLG has nullified the decree and has lifted the
related implementation rule,” the court said. Its ruling is
non-binding and the affected parties may appeal to the Federal
Court of Justice (BGH).

The issue has implications for the international
competitiveness of German industry, which current pays some of
the highest power prices in the European Union.

“The grid fee exemption is important for the survival of
Germany’s energy-intensive companies,” industry federation BDI
said in a statement.

Wednesday’s ruling upheld a complaint brought by network
firms. The exemptions have also meant that consumers paid more
on power bills which include 20 percent transmission network
charges.

The court said the exemptions were not in line with EU laws
requiring equal and cost-based treatment of charges to market
participants.

The European Commission, however, stressed the opening of
its investigation did not prejudge its outcome.

“If this turns out to be the case (that they constitute
state aid), the Commission will further examine whether the
exemption is likely to unduly distort competition in the EU or
whether it can be justified,” it said.

Germany’s economy ministry said it would respond to the
Commission within a month. A spokesman said the ministry had no
role in levying network usage fees so the waiver could not be
considered a form of unlawful state subsidy.

The exemptions also recognised the network-stabilising role
of big companies, he added. Large firms such as BASF
have their own on-site power generation units which are able to
feed power into the public grid.

Still, some analysts said the government, which is already
grappling with public anger over power prices buoyed by
subsidies for renewable energy, is in a tight spot.

“(This) will be a signal for Berlin that the exemptions have
to be reconsidered and possibly changed,” said Hans-Christoph
Thomale, an energy expert at Frankfurt law firm FPS.

($1 = 0.7677 euros)

(Additional reporting by Alexandra Hudson, editing by Jason
Neely)