“The energy shift is a political decision without a
technical concept behind it,” said Stephan Reimelt, chief
executive of GE Energy Germany. “I am very worried about time
running out.”

Germany last summer launched legislation to speed
up its exit from nuclear and to ‘green’ its energy industry.

Once all 17 nuclear plants are switched off by 2022, a key
challenge lies in how to replace the lost supply of inexpensive
round-the-clock electricity with renewable power, which is
unpredictable in its nature.

Economy Minister Philipp Roesler, who joined energy
executives at the Handelsblatt Energiewirtschaft annual
conference in Berlin this week, said the energy shift was a task
to be shared by government and industry.

“But when there’s a plan, it is not the job of the
government to start building, it is the job of the free
economy,” Roesler said.

Yet industry leaders say there needs to be more incentive to
invest in flexible gas-fired power plants for supply when
weather is unfavourable for wind or solar or for when industry
and consumers need peaktime power, for example.

INVESTMENT CASE

Germany’s decision to move away from atomic power followed
last March’s disaster at Japan’s Fukushima nuclear plant. It
undermined utility earnings, annoyed power suppliers in
neighbouring countries and left investors uncertain about the
future.

Industry concerns include run-away subsidies in new niches
like solar power, failing traditional utility business models
and a perceived rift between the environment and economy
ministers over who runs the show.

“Nobody knows what the future energy mix is meant to look
like in detail,” said Serge Colle, managing director energy and
utilities at consultancy Accenture’s German unit.

“It is the policymakers’ task to define concrete targets and
create the conditions so that investments, especially in
baseload supply, add up.”

Danish utility Dong last year bought a site for
a possible gas plant in Ludwigsau, Germany, but CEO Anders
Eldrup said this would only happen if there was “a clear and
convincing business case”.

One solution would be capacity payments which would
guarantee operators earnings for providing back-up power in
standby mode, Eldrup said.

Priority must also be given to the revamp of the network
infrastructure to carry green power to consumers.

RWE Chief Executive Juergen Grossmann said more
money was needed in high voltage power lines across the region
where progress has lagged due to unclear legislation and
citizens’ opposition.

Many energy executives are angry that billions of euros are
being poured into subsidising renewables to create a
decentralised power generation structure instead of funding the
infrastructure.

Claus Sauter, chief executive of German biofuel company
Verbio, suggested that German state bank KfW could
provide part of the investment necessary to make the energy
shift work.

“The state needs to take some risk here,” he said.

Yet Germany’s leading utilities, RWE, E.ON, EnBW
and Vattenfall Europe, should retain a big
role in leading the transformation, Accenture’s Colle said.

“They have critical size to organise the (new) aggregation
and allocation in power supply, promote innovation and set new
technological standards.” he said.

“Those are three points that will be decisive for the
strategy shift to succeed.”
($1 = 0.7802 euros)

(Additional reporting by Tom Kaeckenhoff; editing by Jason
Neely)

Germany, prompted by the March 11 earthquake and tsunami
last year that caused a disaster at Japan’s Fukushima plant,
decided to abandon nuclear power by 2022, leaving a large energy
gap to fill.

Almost a year on, not much has happened to develop
alternatives, executives of Germany’s energy industry complained
at this year’s Handelsblatt Energiewirtschaft conference in
Berlin, the agenda-setting meeting at the start of each year.

“Since the energy shift was announced, not much has
happened,” said Michael Suess, a board member at German industry
conglomerate Siemens who is in charge of the group’s
energy sector.

“We finally need to gain traction now,” he said.

Switching off all 17 nuclear plants by 2022 will lead to a
power gap of more 20,000 megawatts (MW) and the German
government is focusing its plans on new gas plants, as they are
friendlier to the environment than coal plants.

Utilities, are less keen. They say high natural gas costs,
still mostly tied to oil with its inbuilt geopolitical price
premiums, and low power prices make gas plants an unprofitable
business.

“The goals is very ambitious — this will not be easy,” said
Juergen Grossmann, chief executive of Germany’s No.2 utility RWE
.

One of the top priorities is the expansion of transport and
distribution networks for power from renewables sources
including wind and solar, Germany’s new favoured form of energy.

The task is being delayed by protests and overly long
procedures to approve new grids and existing grid revamps, which
in some cases take more than 10 years.

New power networks are necessary to transport power from
renewable sources, notably wind energy, to the south of Germany
from wind turbines in the north, which will be increasingly
placed in the windy high seas offshore Germany.

German energy agency DENA estimates 3,700 km of networks to
transport maximum voltage need to be built by 2025. In the past
few years, however, only 100 km have materialised.

WHO’S PAYING?

Siemens estimates that Germany’s energy shift will cost up
to 1.7 trillion euros ($2.17 trillion) by 2030, most of which
will be borne by taxpayers and power consumers.

Germany’s roughly 900 municipal utilities, seeing a chance
to gain more control over future markets, aim to invest billions
of euros in new power plants and more than double their share in
power production to 25 percent over the next 10-15 years.

The top ten public utilities have said 10 billion euros in
investments would be possible over the next 10 years.

However, executives agreed a more favourable investment
climate was needed to make the envisaged shift become reality.

“The energy sector in Europe must attract private
investments and not just through subsidies,” said Gerard
Mestrallet, chief executive of French utility GDF Suez.

Renewable power – still heavily subsidised to be competitive
against conventional energy sources – is to account for at least
35 percent of Germany’s total electricity mix, up from 20
percent now, according to government targets.

With 7.6 percent, wind power accounts for the greatest share
of renewables in Germany’s energy mix, and according to industry
body BDEW capacity stood at 27,000 MW by mid-2011.

But only a fraction of this is offshore. Only 54 turbines
with a total capacity of 210 MW are so far located off Germany’s
coasts.

This suggests Germany’s goal of installing about 7,600 MW in
offshore capacity by 2020 and 25,000 MW by 2030 seems overly
ambitious. Germany’s Environment Ministry said that to hit the
2030 target, up to 1,500 MW must be installed per year, or one
turbine per year during Germany’s “fair weather season” that
accounts for about half of the year.

Solar power accounted for only 3.2 percent of Germany’s
energy mix in 2011, while swallowing up 8 billion euros, almost
half of all renewable energy costs borne by the country’s
consumers. The government wants to increase that share to 10
percent by 2020.

“Photovoltaic (energy) in Germany makes as much sense as
growing pineapples in Alaska,” RWE’s Grossmann said, referring
to Germany’s limited sunshine.
($1 = 0.7851 euros)

(Additional reporting by Tom Kaeckenhoff, Anneli Palmen and
Markus Wacket; Editing by Anthony Barker)

“We have not yet realised all opportunities in gas. The
measures we have undertaken will serve to attract yet more
liquidity to the EEX,” he said, without giving targets or
precise numbers.

Figures for the 2011 trading results of the bourse, which
also trades power, carbon and coal out of Leipzig and Paris, are
expected around mid-January.

But a calculation of monthly gas trading results issued by
the EEX for 2011 arrived at 58.6 terawatt hours (TWh) which
would be a 25 percent increase over 46.9 TWh recorded in 2010.

Exchange-based gas trading in Germany, Europe’s second
biggest gas market after Britain, was introduced five years ago
and is still small relative to usage of over 900 TWh.

Reitz said that the concentration of Germany’s gas sector in
two central zones, away from a jumble of countless delivery
areas just a few years ago, had helped the EEX achieve higher
volumes.

Also, it extended trading hours, added market makers, that
set reliable prices, and 30 new trading members last year.

The value of gas derivatives trading in Germany’s two key
delivery zones, NCG and Gas Pool, in 2011 had risen by a
double-digit percentage number year-on-year, as more and more
operators linked gas contracts to EGIX, a gas futures index
launched by the EEX a year ago, he said.

The EEX offered spot gas for the Dutch Title Transfer
Facility (TTF) market from last May when it also introduced
24-hour gas trading.

In the fourth quarter, it introduced over-the-counter (OTC)
market clearing for UK gas market products traded at Britain’s
National Balancing Point (NBP), still Europe’s most liquid gas
hub, via ECC.

Reitz said there were increasing calls for European gas
trading to be delinked from crude oil under old-style supply
deals between exporters abroad and domestic distributors, where
the EGIX index was a useful reference tool.

“The gas price should be based on supply and demand of gas,
not on oil prices,” he said.

Reitz also said the ECC was confident that in 2012 it could
win more partner exchanges for its clearing options, apart from
the existing six.

While the bulk of European energy trading is still done
OTC, operators like a clearing bank to eliminate counterparty
risks and without having to pay high exchange fees, he said.

Reitz has been CEO of the exchange and of its clearing house
European Commodity Clearing (ECC) since last August.

He is on the executive board of German-Swiss Eurex, the
derivatives unit of Deutsche Boerse which took a
majority stake in EEX last March.

(Reporting by Vera Eckert; editing by William Hardy)

The figure slightly exceeds the 7.4 GW recorded in 2010,
German network regulatory agency Bundesnetzagentur (BnetzA) said
in a statement on Monday.

Boosted by lavish tariff incentives, Germany became the
world’s largest solar market by installations and a major sales
market of sector bellwethers such as U.S.-based First Solar
, China’s Suntech, Norway’s Renewable Energy
Corp and Germany’s SMA Solar.

But the country has been cutting those favourable tariffs in
an effort to force the industry to lower its costs faster and
head off steep rises in energy bills for companies and
households, which are required by law to pay the feed-in
tariffs.

Additions in December alone amounted to 3 GW, the agency
said, citing preliminary figures and adding that the pace of
installations could trigger a 15 percent cut in tariffs under
the feed-in law for renewable energy from July 2012, if
unabated.

Under previous regulation, it would take the installion of
only 225 megawatts (MW) between January and April of this year
to reach a level that would trigger a 15 percent cut in
subsidies from mid-year, BnetzA President Matthias Kurth said.

“We see proponents of an annual installation cap gaining
influence in the discussion, especially in the context of an
overall weakening economy, making politicians more sensitive to
cost burdens in the manufacturing industry sector,” Equinet
analyst Stefan Freudenreich said.

The contribution of solar to Germany’s overall power output
so far is modest at just over 3 percent, or 18 billion kilowatt
hours (kWh).

DZ Bank analyst Sven Kuerten also said the risk of a hard
subsidy cap on new installations was increasing.

In November, Germany’s Economy Ministry released a paper
proposing to reduce the annual growth of new photovoltaic
installations to 1,000 megawatts, or 1 GW, a move that would
dethrone the country as the world’s largest market for solar
panels.

A similar move caused Spain to fall from a rank as the
world’s biggest market in 2008 to an expected No.8 position in
2011.

(editing by Jane Baird)

The figure slightly exceeds the 7.4 GW recorded in 2010,
German network regulatory agency Bundesnetzagentur (BnetzA) said
in a statement on Monday.

Boosted by lavish tariff incentives, Germany became the
world’s largest solar market by installations and a major sales
market of sector bellwethers such as U.S.-based First Solar
, China’s Suntech, Norway’s Renewable Energy
Corp and Germany’s SMA Solar.

But the country has been cutting those favourable tariffs in
an effort to force the industry to lower its costs faster and
head off steep rises in energy bills for companies and
households, which are required by law to pay the feed-in
tariffs.

Additions in December alone amounted to 3 GW, the agency
said, citing preliminary figures and adding that the pace of
installations could trigger a 15 percent cut in tariffs under
the feed-in law for renewable energy from July 2012, if
unabated.

Under previous regulation, it would take the installion of
only 225 megawatts (MW) between January and April of this year
to reach a level that would trigger a 15 percent cut in
subsidies from mid-year, BnetzA President Matthias Kurth said.

“We see proponents of an annual installation cap gaining
influence in the discussion, especially in the context of an
overall weakening economy, making politicians more sensitive to
cost burdens in the manufacturing industry sector,” Equinet
analyst Stefan Freudenreich said.

The contribution of solar to Germany’s overall power output
so far is modest at just over 3 percent, or 18 billion kilowatt
hours (kWh).

DZ Bank analyst Sven Kuerten also said the risk of a hard
subsidy cap on new installations was increasing.

In November, Germany’s Economy Ministry released a paper
proposing to reduce the annual growth of new photovoltaic
installations to 1,000 megawatts, or 1 GW, a move that would
dethrone the country as the world’s largest market for solar
panels.

A similar move caused Spain to fall from a rank as the
world’s biggest market in 2008 to an expected No.8 position in
2011.

(editing by Jane Baird)

They were responding to a media report on the incident that
highlighted the potential difficulties in maintaining a stable
power supply, a situation closely watched in Europe, since
Germany shut 40 percent of its nuclear capacity last year.

This arose from a political U-turn after Japan’s Fukushima
disaster, leading to the loss of a big slice of stable power
feed, which grid firms must balance to safeguard crucial supply.

“A little over 1,000 megawatts (MW) of Austrian capacity was
being called on during those two days to account for a regional
shortfall, while the Gundremmingen C nuclear reactor happened to
be offline,” said a spokeswoman for TenneT in Bavaria on
Thursday.

“Power supply generally is not under threat,” she said.

Matthias Kurth, president of regulator Bundesnetzagentur,
last August designated 1,009 MW of German and 1,075 MW of
Austrian generation plant capacity as spare reserve should
winter demand run high and renewable output flag.

TenneT added the reason the December incidents were not in
the public eye at the time was that the activation of exactly
such reserves had been anticipated and merely showed the system
was working.

Details on the intervention were posted on the operator’s
website at the time as part of routine disclosure of its
handling of excessive load requirements and did not attract much
attention.

A spokesman for Bundesnetzagentur, the federal network
regulator in Bonn, confirmed the December incident.

“It was a preventive measure and part of daily business,” he
said. “From our point of view, supply is stable and secure.”

The regulator has to ensure overall grid safety to prevent
blackouts, while the country’s four high-voltage network
operators are responsible for the handling of power volumes and
for reporting problems.

Dutch operator TenneT bought E.ON’s 20,000 km
German high voltage grid in 2008, while Amprion, which RWE
last summer sold to a consortium of financial
investors, operates an 11,000 km network.

The other two are 50Hertz, which Belgium’s Elia and
Australian fund IFM acquired from Vattenfall, and
EnBW’s high-voltage grid division.

A collapse of the power system will not happen even in the
worst case that cold, calm weather and lack of sunshine coincide
with maximum demand, experts say. The regulator in such cases
could curb exports or ask industrial consumers to cut their
consumption.

Network operators point out, however, that challenges have
risen for grid managers due to the erratic nature of renewable
supply.

“Last year special measures had to be taken 990 times on 206
days,” the TenneT spokeswoman said. “The year before, it had
been 298 special measures on 161 days.”

These measures, such as so-called redispatch and
countertrading, involve grid managers asking power producers to
wind up or down their respective feeds into the network.

(editing by Jane Baird)

Judge Martin Bach said the men, aged between 27 and 66, were guilty of having participated in a conspiracy to evade around 300 million euros ($393 million) in value-added tax (VAT) between August 2009 and April 2010.

In 2009 and 2010, the European Union’s spot carbon market was hit by so-called carousel trade in which buyers imported emissions permits in one EU country without paying value-added tax (VAT) and then sold them to each other, adding tax to the price and pocketing the difference.

“The convicted were fraudulently involved in tax-evading trades…they have brought the carbon market trading scheme into disrepute,” the judge said.

The EU Emissions Trading System, the bloc’s chief weapon against climate change, caps the emissions of factories and power plants, forcing them to buy carbon permits if needed while also allowing them to sell surpluses.

The way Germany’s flagship lender, Deutsche Bank, conducted emissions trading with some of those that have been convicted had left the door open for tax evasion, he added.

Deutsche Bank said Wednesday that independent legal experts had so far found no wrongdoing on the part of the bank’s employees. Bank staff have testified in the trial and some continue to be investigated, but none have been charged.

^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^

Graphic on how carbon credit fraud works:here

^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^

WIDESPREAD

The Frankfurt district court verdict marks the first convictions after an EU-wide investigation into the fraud, in which Germany carried out the biggest swoop on suspects and investigated 150 suspects and 50 companies in coordination with other EU nations.

European police agency Europol estimates widespread VAT fraud cost EU member states an estimated 5 billion euros in lost tax revenue.

The judge said Germany was the target of fraudsters in the second half 2009 and first half of 2010 after France, the Netherlands and Britain closed legal loopholes.

Germany followed suit only from July 1, 2010 onwards.

Irfan Musa P. from Britain received the maximum sentence of 7 years and 10 months; German Bjoern P. 6 years; his father Robert P. 4 years; Wayne Stewart B. from Britain 4 years; Fraz M. from Britain 4 years and French man Claude B. 3 years.

Robert P., Claude B. and Fraz M. were released for having served parts of their sentences and because there were personal circumstances ruling out the risk of their flight before the next terms of their detention.

The court did not release surnames according to German practice.

A separate trial in Britain is set to start next February, after seven suspects charged with carousel fraud pleaded not guilty in October.

The EU scheme has suffered a series of scandals since its launch in 2005, including permit theft, the recycling of carbon credits and hacking of carbon accounts.

To combat further fraud, the EU Commission proposed in October that spot carbon permits should be classified as financial instruments, but this still has to be approved by the EU Parliament and council of EU member states before it becomes law.

“The carbon market remains weak. More fraud or similar episodes would be quite detrimental,” said Matteo Mazzoni, carbon analyst at Nomisma Energia. ($1 = 0.7628 euros)

(Additional reporting by Nina Chestney, Editing by Anthony Barker)

It would arrive at 47.5 GW in 2022 and 64.5 GW in 2032,
compared with 27.1 GW of capacity installed in 2010, the
agency’s president Matthias Kurth said at a news briefing.

The authority, which supervises grids, said it looked
realistic that fledgling offshore wind capacity could reach 13
GW in 2022 and 28 GW in 2032.

Solar power may reach 54 GW in 2022 and 65 GW in 2032, it
said.

The figures are important to gauge subsidy levels for
renewable power, which under German law must be shared by all
consumers, the requirements for transmission grid expansion, and
for future network stability, given that renewables are volatile
as a power source.

“We are describing what we would need so that we can say
that in 10 years’ time, we will have secure supply and
networks,” Kurth said.

“We will need a realistic grid expansion plan based on our
data, otherwise the ambitious energy strategy change cannot
materialise,” he added.

Germany has embarked on a strategy shift away from
fossil-fuels based production towards green power, and Kurth has
a brief to commit transmission firms and generators to ensure
the right infrastructure is installed in a coordinated fashion.

Wednesday’s data will serve as the basis for plans the
transmission firms must present next June, in order for the
government to finalise grid expansion laws from 2013.

TOP LOAD, DEMAND SEEN STEADY

The maximum load on the high-voltage grids – reflecting top
demand – was assumed to remain steady at 84 GW in a scenario up
to 2022 and German power demand was assumed to be steady at
535.4 terawatt hours (TWh), the agency said.

These are sensitive figures as Germany’s hasty decision this
year to abandon nuclear energy earlier than planned was feared
to be causing stress on networks at high demand times and when
renewable supply is not available due to weather patterns.

Despite zero fuel input and no carbon emissions, the problem
with renewablespower is that without the right weather, there
may not be enough production when needed.

Power cannot yet be stored in great amounts and Kurth said
that prospects for effective solutions were 20 to 30 years away.

The stable demand figure up to 2022 was based on the
assumption that energy efficiency gains would offset consumption
increases arising from economic growth, he said.

The stable load figure hinged on assumptions that better
grid usage and management, and new cables, will help rein in
potential overloads or disruptive load swings on the grids.

More short term, Kurth reiterated that this and next winter
looked supplied enough to cope with the loss of a huge slice of
nuclear energy earlier this year, when Germany shut its oldest
reactors in the wake of the Fukushima disaster.

The Bundesnetzagentur in August made provisions for
coal-fired plants to rev up capacity at times of undersupply
after off 41 percent of Germany’s former nuclear capacity was
switched off permanently.

“We have said we should keep a handle on the situation and
there are no renewed doubts,” Kurth said.

(Editing by William Hardy)

Hildegard Mueller, managing director of BDEW said in an exclusive interview with Reuters the country has started relying more on imports from neighbors after switching off vast nuclear capacities in the wake of Japan’s Fukushima disaster.

“That’s definitely the reason,” she said. “We are no longer a stabilizer of the western Europen network to the degree that we used to be. We are more on the demand side.”

BDEW, a national lobby which represents 1,800 firms in power, gas and water supply, showed imports rose and exports declined, leaving the country a net exporter but at a much lower level than a year earlier.

Imports rose by 16.1 percent to 37.8 TWh in the nine months from January to September while exports declined by 8.7 percent to 39.4 TWh.

Power consumption in Europe’s leading economy declined by 0.6 percent to 388.4 TWh in the nine months compared with the year-earlier period , which BDEW attributed to moderate weather patterns and the start of a macroeconomic slowdown.

Gas usage in the nine months declined by 9.3 percent to 592 TWh compared with a year earlier, BDEW also said, pegging this mainly to lower heating requirements.

“It would be speculative to guess winter demand,” Mueller said. “This will heavily depend on the weather.”

(Reporting by Vera Eckert and Tom Kaeckenhoff)

The law will not cover highly market-sensitive information
on outages on oilfields, long a source of controversy among oil
traders, although knowledge of when associated gas is shut down
could provide a clue.

“Nuclear shutdowns and gas field maintenance would typically
trigger a disclosure obligation,” said Lucas Bergkamp, a partner
at Hunton & Williams in Brussels.

Another international law firm, Cleary Gottlieb, issued a
note saying “inside information” would include anything linked
to “the capacity and use of facilities for production, storage,
consumption or transmission of electricity or natural gas and
use of LNG facilities”.

That would include planned or unplanned disruptions.

“REMIT (Regulation on Energy Market Integrity and
Transparency) is a first step in the extension of traditional
prohibitions of insider trading and market manipulation to
physical commodities market,” the note concluded.

Commission officials said they were working on the precise
details of which data the energy firms would have to publish.

The data will have to be published six months after the
first stage of the law is enforced.

The first step, making insider trading and market
manipulation illegal, will be binding 20 days after publication
in the EU Official Journal, expected over the coming weeks. The
draft rules have already been widely publicised.

For the British wholesale power and gas markets, utility EDF
has started publishing a nuclear outage table, but
information on some other plants and on gas field maintenance
can be hard to obtain.

“The issue (for traders) is that everyone wants to know what
the other one is doing, but no one wants to reveal their
information. Regulation is a way to enforce this, so people
won’t have the choice,” said a gas trader at a major European
utility, who asked not to be identified.

He also raised one of the standard objections to new EU law.

“Enforcing these rules on companies will cost quite a lot.
Updating their systems, etc. requires quite a lot of work,” he
said.

OIL EXCLUDED

Traders and energy companies in Germany took the view it
would change little for a market regarded as a model of
transparency and that the same rules should be applied
elsewhere.

RWE Supply and Trading and E.ON Ruhrgas
reveal on their websites production and outages in real time.

The EEX (European Energy Exchange) also has live information
on installed capacity.

“E.ON supports regulatory plans which serve to strengthen
trust in energy markets, for example transparency guidelines, if
they apply to the whole of Europe uniformly,” an E.ON spokesman
said.

“Transparency is being handled very differently in different
parts of Europe at the moment.”

Commission officials said oil had been deliberately excluded
from the regime, as it is regarded as more international than
Europe’s wholesale power and gas markets.

“Oil is an international commodity. Enforcing transparency
rules needs to be tackled at international, not European level,”
an official said.

“Whereas gas and electricity are fundamentally European
markets, as they need to be delivered by a network.”

Regulating the oil futures market, where the bulk of
international oil trade takes place, has fallen to the Commodity
Futures Trading Commission (CFTC) in the United States, as well
as the British regulator, the Financial Services Authority, and
the EU.

But the publication of supply outages that can have a big
impact on physical oil markets, with knock-on implications for
futures trade, has yet to be covered.

Major oil companies say they have internal barriers designed
to prevent their trading departments benefiting from the
knowledge of field operators about when oil supplies fluctuate
because of outages.

BP and Royal Dutch Shell had no immediate
comment on REMIT.