Major changes in works for Canada's electrical grid - Canada - CBC News

This article provides a very comprehensive picture of the current Canadian electricity system.  A long read but informative and worth it!

The power structure in Canada is changing — not the government, but the country's electricity infrastructure.

By 2020, where electricity comes from and how it gets to your door will have undergone an unprecedented overhaul. Windmills will dot the landscapes of the Great Lakes and remote B.C. Smoke from coal plants will be buried in Saskatchewan and Alberta. A massive underwater cable will feed voltage from Labrador to as far away as New England.

It's all part of a complex series of initiatives that will reformulate everything from who produces the energy that powers your stove or dishwasher, to how they produce it, to your own power consumption habits and how much you'll pay each month.

"Electricity is one of the basic fuels of the economy. Not much happens without it," says Pierre Guimond, CEO of the +Canadian Electricity Association, an industry group. "So getting the basics done correctly — yeah, we've got a lot on our plates."

+CBC News  has analyzed hundreds of studies, contracts, reports, strategy documents, maps and statistics about the country's electrical future. Many of the details have never before been gathered and shared with the public. We've produced the first map, for example, of every major generating station that's operating in Canada today or forecast to start up by 2020. And we've calculated what it will likely cost for your electricity, based on each province's current power generation strategy — and the surprising array  of companies you'll be buying it from.

Will there be enough?

To the tens of millions of North Americans who spent many hours in the dark during the blackout of 2003, the question lingers: Do we generate enough electricity to meet the growing needs of homes and businesses, and do we have a robust enough grid to stave off future outages?

The +Cn Tower  is silhouetted against the setting sun as a blackout grips Toronto on August 14, 2003. As many as 10 million people in eastern North America were affected by the massive power failure. ((Andrew Wallace/Reuters))

In 2003, Ontario, Canada's second-largest powerhouse after Quebec, was on the brink. Its independent grid operator made doomful pronouncements about shortages, and Ontario had to import a sizeable chunk of its energy from the United States.

More recently, British Columbia has become a net importer of current from south of the border. Alberta, Nova Scotia and Saskatchewan also rely on foreign sources.

The outlook has improved, but there's still cause for caution.

Ontario now sends $400 million in electricity to the U.S. each year, while B.C. is aiming to be self-sufficient by 2016. Alberta has seen a torrid pace of generator construction, although a March report by +Canaccord Genuity Wealth Management  predicts the province's power consumption is expected to rise by an estimated 4 per cent a year, putting pressure on the amount of power available and driving prices up. On the East Coast, the hydroelectric development of the Lower Churchill River will eventually bring online enough capacity to power any one of the Atlantic provinces in its entirety. 

Overall, the country's system still needs massive cash infusions.

The International Energy Agency estimates Canada will require $10 billion a year in investments in its electrical infrastructure  from now until 2030. A little over half of that will go towards generation and the rest to improve the bulk transmission  grid and the more modest power lines  that distribute electricity to homes.

The most recent assessment from the North American Electric Reliability Corp. – which is authorized by both the Canadian and U.S. governments to ensure the adequacy of the grids in both countries and ensures there's an adequate power supply — isn't overly rosy, either. NERC says that as of 2012, Quebec "needs additional resources" on its generation side, while B.C. and Alberta still need to "accelerate … resource development" to meet their needs for 2020. Ontario, despite its scheme to bring hundreds of small-scale generation online through guaranteed rate offers, is predicted to be a "tight area." 

How much will it cost?

As a result, in almost every region of Canada, electricity prices are going up . Way up. (Try the interactive calculator  to get an idea of what you'll be paying for base electricity in the coming years.)

Customers in several provinces are already seeing it. BC Hydro raised its rates 7.3 per cent this year and has announced it will seek an additional 30 per cent hike over the next three. The Ontario government declared in late 2010 that the province's rates will rise an estimated 46 per cent by 2015. Alberta still has the fourth lowest electricity cost in the country, but the Canaccord Genuity report noted that the cost of wholesale electricty has surged recently, more than doubling in January and February compared to last year, and it is expected to continue to rise over the next few years.

With the possible exception of Manitoba, nobody will be spared cost increases. A CBC News analysis of provincial utilities' power-purchase agreements and financial statements suggests the average price per kilowatt-hour countrywide will rise more than 50 per cent by 2020.

The Jean-Lesage hydroelectric dam in Baie-Comeau, Que. A large amount of Canada's electricity currently comes from sites like these but the cost to generate power will increase as new, more expensive projects are constructed. ((Jacques Boissinot/Canadian Press))

Until now, prices have stayed relatively low — among the cheapest of the nations belonging to the Organization for Economic Co-operation and Development (OECD) — because the majority of Canada's power comes from hydroelectricity, most of which was developed decades ago and has been paid off for years. The operating costs of hydro dams are minimal, which is why Quebec can generate its power for a couple pennies per kilowatt-hour.

But those power plants are no longer enough to meet the country's needs. And the new plants being built, plus the copper and aluminum heavy-transmission lines to reach them, will cost a lot more. The end result is that ratepayers will end up footing the growing bill.

"Newer hydro that has been built is a lot more expensive than what was built generations ago," the Canadian Electricity Association's Pierre Guimond says. "Everything is more expensive nowadays, because the sites are further away, they're more difficult to develop, and that is reflected in the cost of electricity."

Take Quebec's current biggest hydro project, a series of dams on the Romaine River north of the Gulf of St. Lawrence. It's anticipated to generate power at a cost of close to 6.4 ¢/kWh — or more than three times the price of electrons from that province's currently installed capacity.

What's happening with hydro is happening with every kind of generation. In Ontario, new wind farms get paid 13.5 ¢/kWh, and rooftop solar systems 80 ¢/kWh. A recent power industry study found new nuclear plants cost twice as much to build as they did only seven years ago. Coal-fired plants, once a cheap source of energy based on an abundant fuel, cost far more because of emissions restrictions.

It spells certain pain for consumers' wallets.

"We've underinvested in our electricity system across the country for decades," says Tim Weis, the director of renewable energy and efficiency policy for the Pembina Institute, a national think-tank on sustainable energy. "Whatever you're going to build today is going to be more expensive."

Who will generate it?

Crown-owned utilities once dominated the production and transmission of electricity. A recently as 10 years ago, more than 80 per cent of the generating capacity in Canada was run by provincial governments. But since then, the private sector has held sway.

In the past, most of the generating capacity has been owned by public companies, such as the Pickering nuclear plant. By 2020 nearly all of the new generating sites will be privately owned. ((OPG))

All new net generating capacity constructed since 2000 has been by private companies, and virtually all planned future net capacity will be built by the private sector. From now until 2020, private power sources will grow by almost 50 per cent countrywide, whereas government-provided electricity will nudge up a mere three per cent.

In British Columbia, where the government's procurement policy for new power sources relies almost exclusively on for-profit corporations, companies like General Electric are building hundreds of megawatts of new generating capacity.

In Alberta, oil patch heavyweights Suncor, Imperial Oil and TransCanada are putting up big plants fuelled by natural gas.

In Ontario, +TransAlta Corp. runs four gas-fired stations, but also three wind farms. And in the Maritimes, TransAlta is erecting dozens more wind turbines alongside a host of small specialist companies.

For some critics, it's a disquieting trend: Natural resources such as waterways are falling into private hands, while consumers pay higher prices to effectively subsidize the private development of new industries in solar and wind power. There are also few if any provisions for all the new generating assets to transfer to public ownership once the companies' power-purchase contracts are up, and no guarantees those companies won't seek to hike their prices when that day comes.    

Where will it come from?

A worker pulls on a rope to help guide the blades while installing a wind turbine for Toronto Hydro at Exhibition Place on Dec. 18, 2002. The future of generation lies in wind and gas, experts say. ((Kevin Frayer/Canadian Press))

The first half-century of electrification in Canada was all about the country's hydro power. Then came coal, oil and nuclear. The future is written in wind and natural gas.

From fewer than 100 megawatts in wind turbines at the dawn of the millennium, Canada has been rapidly expanding its capacity   to 3,500 MW today, and plans to have 12,765 MW by 2020. That still represents less than 10 per cent of national capacity, but the country is adding more wind power than any other type (with the possible exception of hydro if the full development of Labrador's Churchill River proceeds). And the extra capacity will help enable the shutdown of one of the country's worst sources of greenhouse gas, the Nanticoke generating station in Ontario.

The move away from coal will also be aided by the slew of gas-fired plants that have started up in the past decade. While politicians prefer to tout their provinces' investments in enviro-chic renewable power, the reality is that natural gas is driving the grid's expansion. Sixty per cent of the new generation built in the 2000s is gas, and the sector is slated for another 25 per cent growth by 2020.

It's not perfect — the best gas-powered plants still emit about 40 per cent of the green house gases (GHGs) of a coal-based generator — but staring at the bogeyman of global warming, it's a significant step.

How dirty will it be?

High voltage power lines spread out from Ontario Power Generation's Nanticoke Generating Station. Ontario will shut down 11 of its coal-fired plants by 2014. ((Frank Gunn/Canadian Press))

The electricity sector is far off track from meeting its share of Canada's Kyoto emissions commitments (try the emissions calculator  to see just how far, and experiment with ways to minimize them). The sector emitted 117 million tonnes of GHGs last year, down from a peak of more than 130 Mt in 2003. But that level is still well above the 89 Mt the industry would have to trim to by 2012 to be in line with the Kyoto protocol.

"It was pretty clear that there wasn't going to be an effort made to meet that target," the Pembina Institute's Tim Weis says. "It wasn't an unrealistic goal; we were just too slow to go get going."

Looking ahead, though, the emissions picture gets somewhat better.

The federal government has set its own goal of cutting GHGs 17 per cent from 2005 levels by 2020. Under that scheme, power plants would have to cut back to 102 Mt in emissions in the next nine years, and they may be able to achieve it.

Ontario will shut down all 11 of its remaining coal-fired units by 2014, while Alberta and Saskatchewan are exploring new (though still unproven) ways of stashing their coal plants' carbon dioxide underground. Add to that Ottawa's plan to put strict emissions caps on coal-fired power plants, and the sector could hit the federal government's milder GHG target.

If it doesn't, Canada will have a hard time achieving any emissions-reduction objectives. Electricity generation accounts for a sixth of the country's GHGs, the second-largest source after transportation.

"The government needs to lead, whether at a federal or provincial level," Weis says. "Anywhere you've seen major reductions, whether in Europe or Ontario, it's all happened because the government has taken the initiative to make it happen."

Transmitting Canadian Hydroelectric Power to the USA via Submarine Cable

Such an interesting article with big picture thinking we all need. This article incorporates elements of interprovincial transmission concepts and Canadian energy exports throughout the US. Very timely and interesting read.

Transmitting Canadian Hydroelectric Power to the USA via Submarine Cable

Harry Valentine, Commentator/Energy Researcher

Canada has for decades, exported hydroelectric power from Quebec and from Labrador into markets in the northeastern USA. California has periodically imported hydroelectric power from British Columbia. A power transmission company based in Vancouver has proposed to install a submarine power cable along America's Pacific coast to carry electric power from British Columbia to California. A transmission development company in Toronto is formulating plans to install a submarine power cable under waterways that link Montreal and New York City, for the purpose of carrying hydroelectric power to that city from dams at James Bay.
A recent announcement from Newfoundland in Eastern Canada involved plans to carry hydroelectric power from Labrador to Northeastern American markets via submarine power cables installed under 2 straits along Canada's Atlantic coast. The province of Manitoba that has much undeveloped hydroelectric generating capacity along the Nelson River and Churchill River, has indicated the interest in exporting some of that power into Midwestern American markets at some time in the future. It may be possible to carry that power via submarine power cable installed under northern riverbeds, Lake Winnipeg and the Red River, with potential to extend the cable through the riverbeds of tributaries and over a short distance across land into the headwaters of the Mississippi River.
Submarine power cables installed in the riverbed of the Mississippi River could connect to similar cables that carry power to cities such as Minneapolis-St Paul, Chicago, St Louis and Kansas City. However, Manitoba Hydro may only have enough undeveloped generating capacity (some 10,000MW) to meet up to 40% of future Midwestern American power requirements that may increase by up to 25,000MW by 2030. Midwestern American power providers may consider obtaining competitively priced Canadian hydroelectric power from Hydro Quebec, via one of 2 direct routes. A third indirect route would see a submarine cable across southern Hudson Bay linking the power dams of Hydro Quebec and Manitoba Hydro.
Montreal-Chicago link:
The is potential to install a submarine cable along the south side of the St. Lawrence River, between the navigation channel and the riverbank from Montreal to Lake Ontario. There is a canal along the south side of the Moses-Saunders power dam near Massena NY that may provide the submarine cable with a route around the power dam and the navigation locks. The cable may follow the south shore of Lake Ontario to any of several streams located to the west of Rochester NY, that have origins near the barge canal that connects Tonawanda NY to Syracuse NY.
That barge canal connects to the channel that carries water from Lake Erie to Niagara Falls and may carry a submarine into the south side of Lake Erie, where it may reach Toledo and Maumee River. The Maumee River connects into the Wabash River that has a tributary with headwaters located near the headwaters of a tributary of a river system that carries water to Chicago. The capacity of the submarine cable may provide potential to serve other possible power markets at Erie, Cleveland and Toledo.
While a submarine cable is possible between Montreal and Chicago, it needs to be a reserve option to a shorter and more direct route between the power dams of Quebec and Chicago. Mutually cordial and cooperate intergovernmental relations between New York State, Ohio, Indiana and Illinois would make such the optional southern route possible. Canadian politics will ultimately determine the route of the submarine power cable between Quebec and Chicago.
Direct James Bay -- Chicago Link:
A direct link between the hydroelectric power dams near James Bay and Chicago would cross over Ontario. It may involve submarine cables installed along the eastern shore of James Bay and in the riverbed of the Moose River and tributary the Missinaibi River that has headwaters near rivers such as the Magpie and the Whitefish that flow into Lake Superior. The cable would continue along the eastern shore of Lake Superior and under the navigation channel to the northern coast of northwestern Michigan.
There are several streams in northwestern Michigan with headwaters in close proximity that flow to Lake Superior and to Lake Michigan. Depending on the nature of intergovernmental relations between Illinois and Michigan, it may be possible to install submarine cables in such riverbeds. A submarine cable buried under riverbeds across northwestern Michigan may be extended south along western Lake Michigan to Milwaukee and Chicago. The overall distance between the power dams of Quebec and Chicago would match the distance between the power dams and New York City and be 1/3^rd shorter than the link via Montreal.
Canadian Negotiations:
A direct connection between the Quebec power dams and Chicago would depend on future negotiations between Quebec and Ontario. Ontario wanted to purchase hydroelectric power from Labrador via a power line across Quebec, except that political differences between the governments of Quebec and Newfoundland precluded such an arrangement. A submarine cable under the Lower St. Lawrence River may be possible, given that that river is under joint jurisdiction of the both the Federal Government of Canada and the Government of Quebec.
Ontario may be agreeable to an American-owned submarine power cable connecting between Lake Superior and James Bay through rivers that flow across northern Ontario. James Bay is under Federal Canadian jurisdiction and there would be opportunity to negotiate to install a submarine cable under the seabed near the eastern shore of James Bay, to the a point where Hydro Quebec would provide a connection to their hydroelectric power dams. Quebec's willingness to allow Ontario to acquire hydroelectric power from Labrador would likely enhance prospects for a shorter link between Quebec's power dams and Midwestern American markets.
Lower St. Lawrence River Cable:
High-ranking officials of the Federal Government of Canada have indicated their interest in developing an east-west power connection across Canada. In this regard they may advocate and facilitate the installation of a submarine power cable from Labrador at the Strait of Belle Isle and upstream along the Lower St. Lawrence River to either the Upper St. Lawrence River or the Ottawa River. It is possible that influential political forces in Quebec may allow for a submarine cable to follow the bed of a river that flows from Labrador through Quebec into the Gulf of St. Lawrence.
Modern drilling technology allows for the drilling of circular conduits under the control dams along the river system, to allow submarine power cables to be "threaded" through the conduits. The submarine power cable may be routed to the Canadian side of the Moses-Saunders international power dam, from where it would connect to an upgraded overland power transmission line to carry electric power to Toronto. The submarine power cable may follow an alternate route up the Ottawa River (also under Federal Canadian jurisdiction) from Montreal to Ottawa, from where a high-density power line that is due for upgrading connects through to Toronto.
Political Opposition:
There is the likelihood of influential political forces using the judicial system to prevent the installation of a submarine power cable along the Lower St. Lawrence River that may carry electric power from Labrador to Ontario. Such action would undermine the credibility and authority of the Federal Government of Canada and serve the interest of secessionist political elements in eastern and western Canada. It would also leave Quebec with the option of a submarine cable carrying electric power from Montreal to Midwestern American markets using a longer southern route.
Ontario would be left with the option of purchasing Canadian hydroelectric power from Labrador via buried power cables installed along rail and roadbeds across the northeastern USA, to the Moses-Saunders power dam. However, the successful installation of a submarine power cable under the St. Lawrence River, between the Gulf of St. Lawrence to either the Moses-Saunders power dam or to Ottawa, would affirm credibility of the Federal Government of Canada. It would also provide Ontario with access to a source of competitively priced, renewable electric power from another region of Canada.
Conclusions:
Labrador (Newfoundland) and Quebec are literally competing against each other in the export of hydroelectric power into northeastern American markets. Such competitive rivalry has undermined cordial intergovernmental relations in Eastern Canada. Ontario could offer an option for Quebec to export hydroelectric power to Midwestern American via a short route, provided Quebec allows Ontario to receive hydroelectric power from Labrador via the St. Lawrence River. Such an arrangement would maximize hydroelectric power generation in both Labrador and Quebec, giving American markets the option of competitively priced renewable electric power.

Too much power? Solution for too much wind energy

There is no question that we often need to give away and export of electricity when demand is low and production is up.  Why not find ways to utilize all of our excess electricity when demand is low?  Doing this through heat storage curtails our fossil fuel consumption, and provides us with lower cost heating options.  Great concept.  Would love to see more test programs developed with the Ontario smart metering roll-out.

January 20, 2011

Possible solution to storing wind power

Column | Korky Koroluk

A simple, low-tech solution to the problem of storing wind power is undergoing testing in three small North American markets — one in Summerside, P.E.I., and two in Maine.

In the process, it is showing how alternative energy is able to offer new jobs for HVAC engineers and contractors.

The solution involves not centralized storage in one large plant, but “distributed” storage involving small ceramic heaters in peoples’ basements. It’s also being installed in a few small commercial buildings.

Critics have often criticized wind or solar energy installations because the wind doesn’t always blow and the sun doesn’t always shine. Intermittent sunshine has been overcome by building concentrating solar plants which, on sunny days, store energy as molten salts that are later used to produce steam turbines. It’s a system that is now being used in several places in the world, most notably Spain and the American Southwest.

Now researchers have come up with ceramic heaters, which are nothing more than extremely dense ceramic blocks in insulated cabinets. The blocks store energy as heat when the wind is blowing, then release it slowly over the next day or two.

The American experiments have been under construction for several months; the Summerside project is just beginning.

Prince Edward Island produces a lot of wind power. The problem is that the wind tends to blow more at night when energy demand is low. Because of this, the province has been selling some of that surplus energy to mainland markets, but at low rates.

But at a recent meeting of Summerside city council, homeowners were asked to buy the ceramic storage systems.

The heaters are expensive, though, at about $2,000 each. They are expected to save money over the long term, but that is often not sufficient to get people to act. That’s why the city is offering users a break on their electricity prices that could amount to about $600 a year. City fathers hope that will lead to at least 100 sales this year.

In Maine, getting people to convert to distributed wind energy is more urgent because oil is used to heat 80 per cent of all homes in the state. That’s why the incentive for switching off oil is somewhat sweeter.

For a start, the Highland Wind project developer, Independence Wind, is offering any participating household a $6,000 “wind for oil” grant. The money is to fund the purchase of one of the ceramic-block units, although it can be used for any renewable energy or efficiency investment.

In return for providing the storage, Highland Wind will supply wind power to residents at a deeply discounted price.

Fuel oil is presently running at about $3 (U.S.) a gallon. The discounted price will be equivalent to about $1.15 per gallon of oil.

The other Maine project involves Vinalhaven Island — an entire island with small communities dotted around it that has committed entirely to wind power. But like P.E.I., it has had to sell some off-hours power or shut down some of its turbines.

The project looks like a winner for the local economy, as well as individual users.

The total project is estimated to cost more than $210 million, most of which will go directly into the state economy through engineering, environmental, construction and related jobs. At peak construction, the project will bring more than 300 jobs to the local region. And every year, the project will pay more than $500,000 in state, local and county taxes.

That’s a lot of benefits for the application of what is really an old idea. There is, after all, nothing new about using ceramic blocks to store heat, and similar heaters are already in use in Britain to even out peak demand on its electricity grid.

But an old idea becomes new again if it means reduced reliance on oil.

EDF's Solar `Time Bomb' Will Tick On After France Pops Bubble

Jan. 19 (Bloomberg) -- France’s solar power boom that’s led to farmers building unneeded barns just to cover them in panels is costing Electricite de France SA more than a billion euros ($1.3 billion) a year as it meets state pledges to pay above- market prices for renewable energy.
French payments for solar-generated electricity sold into the distribution grid were the highest in Europe in 2009, leading to a 10-fold capacity increase in two years. What’s been a boon for panel owners and manufacturers has hit EDF because a tax to cover the higher costs of renewable electricity has fallen short.
“This is a time bomb EDF needs to defuse as soon as possible,” Bertrand Lecourt, an analyst at Deutsche Bank AG, said by telephone from Paris. While “the totally out-of-control phase” could be over, “it’s still something to be watched carefully,” he said.
The cost is siphoning off funds from EDF as it plans to spend 35 billion euros to extend the life of France’s aging nuclear plants. Europe’s largest power producer also aims to invest tens of billions of euros building plants in the U.K., China and Italy. The tax shortfall will widen this year and last until 2017 even as the government moves to cool the solar rush, said Aurel BGC analyst Louis Boujard.
EDF shares have dropped 20 percent over the past year, compared with a 3.7 percent decline in Europe’s Stoxx 600 Utilities Index. The Paris-based company had net debt of $57 billion euros at the end of June, according to a company filing.
Elsewhere in Europe, governments have stepped in to contain spiraling growth in solar generation.
Spanish Limits
The Czech Senate introduced a temporary tax on solar producers in December, and Spain limited the hours during which existing solar parks can earn premium rates. Germany almost doubled the surcharge consumers have to pay in renewable-energy subsidies starting this year.
To end what it has called a “speculative bubble,” France on Dec. 10 imposed a three-month freeze on solar projects to devise rules that could include caps on development and lowering the so-called feed-in tariffs that pay the higher rate for renewable power. The tariffs were cut twice in 2010.
“We just didn’t see it coming,” French lawmaker Francois- Michel Gonnot said of the boom. “What’s in the pipeline this year is unimaginable. Farmers were being told they could put panels on hangars and get rid of their cows.”
Solar Projects
The French cuts haven’t slowed demand for new solar projects. EDF received 3,000 applications a day to connect panels to the grid at the end of last year, compared with about 7,100 connections in all of 2008, according to the government and EDF. France could reach its 2020 target of 5,400 megawatts of solar generating capacity by the end of 2011 if all proposed projects are completed.
France’s energy regulator estimates EDF will pay an average of 546 euros a megawatt-hour for solar power in 2011. That’s almost 10 times estimated spot market power prices of 55 euros, and the highest among renewable energy sources.
The promise of rich returns spurred suburban supermarkets to put photovoltaic panels in parking lots and farmers to install units on empty, purpose-built barns, according to a French parliamentary report.
“Most panels installed in France were made in China with a highly questionable carbon footprint,” Environment Minister Nathalie Kosciusko-Morizet told parliament last month. Policy must “create jobs in France, not subsidize Chinese industry.”
The higher payments for renewable power are supposed to be covered by a levy added to consumers’ electricity bills, which also pays for the supply of power to needy households. For the last two years the CSPE levy, which remained at 4.50 euros a megawatt-hour between 2004 and the end of 2010, failed to keep up with the mounting costs.
Raised Tax
France raised the tax to 7.50 euros a megawatt-hour from Jan. 1, short of the 12.90 euros the regulator estimates is necessary to eliminate the shortfall through the end of 2011.
The new level and further increases in the coming years may allow EDF to reach a “balance” in the system by 2017, Aurel BGC’s Boujard said by telephone.
“EDF shouldn’t have to pay for renewable energy development in France,” Boujard said.
EDF’s shortfall was 1.4 billion euros in 2009, and is estimated to exceed 1 billion euros in 2010, the Commission de Regulation de l’Energie said in a report published this month. With the CSPE set at 7.50 euros a megawatt hour this year, the shortfall will reach an estimated 3 billion euros at the end of 2011 because of the increase in solar capacity, according to data in the report.
The solar component of the tax shortfall will rise to about a billion euros in 2011 compared with 60 million euros in 2009, according to Philippe de Ladoucette, head of the agency.
The development of wind and solar energies is “widening a deficit considerably,” EDF Chief Executive Officer Henri Proglio told Senators Dec. 14. “One can’t ask EDF to be the banker for marginal or local industries,” he said.