NRG Energy Inc. and South Texas Project Nuclear Operating Company filed a Combined Construction and Operating License Application (COLA) with the Nuclear Regulatory Commission (NRC) in September to build and operate two new nuclear units at the South Texas Project (STP) nuclear power station site. The total rated capacity of the new units, STP 3 and 4, will equal or exceed 2,700 MWs. NRG expects to bring the units on line in 2014 and 2015
This is the first license application submitted to the NRC for a new nuclear plant in 29 years. The South Texas Project Nuclear Operating Company, which currently operates units 1 and 2, will operate the new units.
Illustration of a duct balloon with a flexible tube to vent dehumidification equipment installed at a New Jersey plant. Courtesy of GR Werth & Associates Inc. Click here to enlarge image
The 12,200-acre site and 7,000-acre cooling reservoir in Matagorda County, Texas, were originally designed for four units.
NRG has chosen Advanced Boiling Water Reactor (ABWR) technology for the new units. Four ABWR units have been successfully commissioned in Japan, with another three units under construction in Taiwan and Japan. The Tokyo Electric Power Co. Inc. has more than a decade of experience in ABWR operations and has provided support for STP’s planned two-unit expansion.
In June 2006, NRG filed its letter of intent to submit an application with the NRC to construct STP 3 and 4. STPNOC, together with a contracting team that includes GE-Hitachi Nuclear Energy and Bechtel, has prepared the COLA for STP units 3 and 4 in just over one year for submittal to the NRC.
With the COLA submitted, the NRC begins an estimated two-month acceptance review process. It is then anticipated that the NRC could take up to 42 months for its detailed review process including staff discovery, site visits, company responses, hearings and NRC Environmental Impact Statements. Assuming this schedule, NRG would hope to receive its license approval and begin construction in 2010. With this time frame, unit 3 should come on line in 2014 and unit 4 in 2015.
Coal Project Owners Agree to Carbon Offsets to Obtain Transmission Line
Seven regional utilities building a 630 MW coal-fired unit at a site in South Dakota have agreed to a plan that would offset carbon dioxide (CO2) emissions from half of the power the unit would create, which is the amount of the output that would be for Minnesota customers. The owners have agreed to the carbon offset plan in order to obtain permission from Minnesota regulators to upgrade a transmission line to carry power from the plant to Minnesota customers.
The settlement between the utilities and the Minnesota Department of Commerce calls for a multi-faceted program consisting of up to six components to offset half the estimated 4.7 million tons of CO2 that will be produced annually by Big Stone II, a supercritical unit scheduled for commercial operation in 2012. Big Stone II, to be built at Big Stone City, S.D., near the Minnesota border, is to supply power to seven utilities including Otter Tail Power and Great River Energy in Minnesota. Other customers served by the new unit are in the Dakotas, Iowa, eastern Montana and Wisconsin. South Dakota already has approved site plans for the plant.
Under the agreement, the seven utilities would be allowed to choose their own methods to offset CO2, said Dan Sharp, spokesman for the Big Stone II project. They could include capturing and sequestering some of the CO2, buying carbon credits and/or setting aside $10 for each ton of carbon dioxide emitted for the Minnesota load portion. Those funds could be used for future purchases on a trading exchange. The exchanges could also use the money to fund environmentally friendly projects such as tree planting to offset or neutralize the effects of utility greenhouse gases. The utilities could also invest in technologies aimed at reducing CO2 emissions.
Any combination of up to six methods to achieve the determined offsets could be employed. The utilities also agreed to build or buy at least 180 MW of energy produced by wind farms owned by local communities or cooperatives, to improve their conservation efforts and to reduce mercury emissions from the existing plant.
“It’s aggressive and it is the first plan in the country to deal with carbon,” said Edward Garvey, the state’s Deputy Commerce Commissioner in charge of energy and telecommunications. “The key thing is they actually (reduce carbon emissions) and they do it in a way that is quantifiable, verifiable and permanent.”
But environmental groups that have opposed the project say the agreement is “empty-handed” and a step backwards from Minnesota Gov. Tim Pawlenty’s pledge to reduce fossil fuel use in the state. Pawlenty signed a bill earlier this year pushing utilities to reduce greenhouse-gas emissions by 15 percent by 2015 and 80 percent by 2050.
Nuclear Plant Would Co-Produce Power and Biofuels
Various energy pundits have long proposed building nuclear power plants dedicated to producing specific products or supplying power and/or thermal energy to serve defined strategic needs. These ideas have included the prospect of building nuclear plants solely to make hydrogen should public policy ever dictate a shift to a hydrogen economy to replace petroleum for transportation needs. The rationale is that nuclear power provides extremely low cost electricity that is essentially impervious to rising fuel costs and produces no emissions or greenhouse gases.
Another proposal for specifically targeted nuclear power facilities has been to supply thermal energy for what is likely to be a flourishing oil shale extraction industry, whereby petroleum is extracted from tar sands and shale in Canada and some U.S. states. Today, that industry is using natural gas to extract oil, a fuel that is not only expensive, supply-constrained and needed for other uses, but produces about half as much greenhouse gases as coal.
Now, a proposal has surfaced to build a nuclear power plant in the United States to produce power, ethanol and perhaps even a form of synthetic natural gas that could substantially augment domestic natural gas supplies. Alternate Energy Holdings International (AEHI), a publicly traded company formed in September 2006, is forming a cooperative arrangement with dairy farmers to develop a nuclear plant dubbed the Idaho Energy Center that would co-produce power, ethanol and methane.
With a market value of $20 million and no debt, the company is in the early stages of its Nuclear Regulatory Commission (NRC) application process. AEHI is reviewing financing options and seeking large investors. The proposed $3.5 billion commercial nuclear power plant/bio-fuel generation facility would be built near Grand View, Idaho. The plant would initially produce 1,600 MW of power to the local grid. Waste heat from the nuclear reactor would be used to produce ethanol and methane from local crops and agricultural waste.
The Generation 3+ reactor uses a hybrid cooling system that requires minimal cooling water. AHEI said the Generation 3+ plant could produce power for 1-2 cents/kWh. The excess heat from the plant will be used to produce bio-fuels, specifically ethanol and methane. This production method is expected to reduce the cost of ethanol to less than $1 per gallon, according to AHEI. The first plant using the design is currently under construction by TVO in Finland and is expected to be the first new nuclear unit to go into service in Europe since the 1980s.
Waste heat from the project would be used to make up to 100 million gallons annually of ethanol from local crops of potatoes, sugar beets and corn. Don Gillispie, AEHI chief executive, said the methane production numbers are still being developed. “The processes use low-tech systems and methane can be produced cheaper and faster with waste heat than using electricity,” he said.
AEHI has entered into an agreement with UniStar Nuclear to build the plant using the U.S. Evolutionary Power Reactor (U.S. EPR) Generation 3+ design. Under the deal, UniStar Nuclear, the joint enterprise of Constellation Energy and AREVA, will help AEHI seek regulatory approval and in subsequent construction. AEHI also selected the U.S. EPR as its technology. Plans call for filing for a construction and operating license (COL) with the NRC by the end of next year, with construction to begin in late 2011 and startup slated for 2015.
Gillispie said the Idaho site will support three units, but only one is being requested. The company eventually could build six units. Two of the three electric utilities in Idaho and several other utilities outside the state have indicated an interest in buying power from the project.
The Idaho nuclear proposal is one of more than two dozen new U.S. nuclear units expected to seek COLs in the coming months. In late September, NRG Energy became the first to file its COL application with the NRC for 2,700 MW of new capacity at the South Texas Project (see previous news item). The NRC expects new COLs for as many as 29 reactors at 20 sites over the next three years. Among the utilities expected to file for new reactors are the Tennessee Valley Authority for its Bellefonte site in Alabama; Duke Energy for its Lee Station in South Carolina; Dominion Energy for the North Anna site in Virginia; Southern Co. for its Vogtle plant in Georgia; and South Carolina Electric & Gas for its Summer station. Florida Power & Light has also indicated interest in building two new nuclear units at its Turkey Point nuclear complex by 2020 and plans to add 400 MW of capacity to its existing Turkey Point and St. Lucie nuclear plants for operation by 2012.Ã¢â‚¬”Steve Blankinship
Illinois Coal Plant Gets Good News
Peabody Energy’s proposed 1,600 MW mine-mouth Prairie State power plant got a double helping of good news when a federal appeals court rejected a challenge by environmental groups and another power provider agreed to buy an equity interest in the project.
In late August, a three-judge panel from Chicago’s 7th Circuit U.S. Court of Appeals affirmed the air permit granted last year by the Illinois Environmental Protection Agency (IEPA). Construction has begun at the site in Washington County in Southern Illinois.
In the latest challenge to the plant, the Sierra Club and the American Lung Association maintained that instead of burning Southern Illinois coal mined at the site, Peabody should be required to use low-sulfur coal from Wyoming. The judges ruled that requiring such a move would force Peabody to redesign the power plant. The appeals court panel said such a move is outside Clean Air Act requirements specifying that plants must use best available control technology .
Judge Richard Posner said that regulating agencies such as the IEPA, and not a reviewing court, should rule on such requirements. The IEPAÃ¢â‚¬â„¢s previous decision to grant the air permit was affirmed by an environmental appeals board at the U.S. Environmental Protection Agency. Peabody said the appeals court’s decision confirms that Prairie State’s technologies will adequately satisfy state and federal environmental regulations to protect the environment.
Days after the ruling, Peabody said it had entered into an agreement with Southern Illinois Power Cooperative (SIPC), which plans to buy a 125 MW equity share of the project. Prairie State’s other partners include American Municipal Power-Ohio, Illinois Municipal Electric Agency, Indiana Municipal Power Agency, Kentucky Municipal Power Agency, Missouri Joint Municipal Electric Utility Commission, and Northern Illinois Municipal Power Agency.” -Steve Blankinship
TXU Buyers Hope for Higher Gas Prices
The largest leveraged buyout in history passed its last major hurdle on September 7 when TXU Corp. shareholders voted to sell the company to private investors Kohlberg Kravis Roberts & Company and Texas Pacific Group for $45 billion, including the assumption of debt. Almost 57 percent of TXU’s 461 million shares were voted in favor of the offer of $69.25 per share. The deal now requires only the approval of the Nuclear Regulatory Commission to become final Ã¢â‚¬â€œ an approval expected this month.
One reason why the deal looks so promising to shareholders is that natural gas prices continue to drive the Texas power market and TXU is in a strong position to sell power at prices set by gas-fired generation using far less expensive coal and nuclear generation. That’s because within the deregulated wholesale and retail power markets of the isolated Texas grid (ERCOT), more than half of the capacity is gas-fired. In states where coal is the dominant fuel, lower-cost coal generation drives the market.
According to financial analysts and filings the company has made with the Securities and Exchange Commission, the higher natural gas prices go, the more TXU is worth. “If gas prices go up, it has this disproportionate impact on the wholesale price of electricity in the state,” independent utility consultant Ken Rose said in an interview published by the Fort Worth Star Telegram. When that happens, he said, TXU makes money from sales on coal and nuclear power.
Although TXU has owned and operated a large fleet of steam cycle natural gas plants for many decades, in recent years the company has provided some of the state’s lowest cost power from its lignite/coal plants, which have been built over the past three decades, and its two-unit Comanche Peak nuclear plant completed in the late 1980s.
Since full deregulation took effect in Texas in January 2002, TXU has sold or mothballed many of its older, inefficient steam cycle gas-fired units. Last year, TXU generated 67,621 GWh, around 6 percent of which came from gas plants. Almost two-thirds came from its lignite/coal plants and the rest from Comanche Peak. Neither coal nor nuclear fuel costs are nearly as volatile as natural gas prices, which have risen two to three fold since deregulation. The generation cost advantage that resulted helped TXU earn a record $2.55 billion in 2006.
TXU hedges against natural gas prices going lower rather than higher, which is the opposite of what many other electric utilities do. TXU’s chief financial officer David Campbell said coal and nuclear units produce power at the cost of coal and nuclear, but the price the company can get for that power is driven by the wholesale market, whose prices are set by natural gas.
According to regulatory filings by TXU, the acquisition offer of $69.25 a share implies long-term gas prices ranging from $7.90 to $9.60/mmBtu at the Henry Hub, a standard benchmark for U.S. gas prices. That compares to the current price in the range of $5.50 and an average of just over $6.50 for the past five years. Some benchmarks established to predict gas production profits have established a range of $4 to $10 through 2015.
And as a state with one of the fastest growing populations in the U.S., the ERCOT market bodes well for TXU’s prospects. During peak periods, demand will almost certainly be met with gas plants, some of which are mothballed. In that case, gas prices increase more than they might otherwise, since more gas will be needed to run what are in many cases low efficiency units. That could push electricity prices even higher.
Daniele Seitz, a financial analyst for Dahlman Rose & Co., said the high value of TXU is primarily due to the ability of its generating fleet to produce power below the price established by the gas-driven market in ERCOT. “The outlook is that their value will continue to rise as more gas comes into the fuel mix,” said Seitz. -Steve Blankinship
Construction & Contracts
Brazos Electric Power Cooperative Inc. agreed to buy more than 40 percent of the power generated at a proposed Central Texas coal-fired plant in a deal said to enable developers to break ground on the project later this year. Waco-based Brazos said it plans to buy 375 MW from Dynegy Inc.Ã¢â‚¬â„¢s Sandy Creek Energy Station, a 900 MW plant to be built southeast of Waco. The plant will use coal from the Powder River Basin in Wyoming and is expected to commence operations in 2012.
Pod Generating Group announced the award of its first two standard offer contracts with the Ontario Power Authority. The pair of 10 MW solar projects represents one of the largest renewable project that can be connected to a local distribution system within the OPA’s standard offer program guidelines. Together, the two facilities represent an investment of over C$100 million dollars. The solar facilities are slated for operation by the end of 2008.
DTE Energy signed a long-term agreement with Michigan-based renewable energy company Heritage Sustainable Energy, LLC to provide wind supply for the company’s GreenCurrents renewable energy program. The 10-year agreement will enable Heritage to build a 6,500-acre wind farm in Richland, Mich., which will start up with two 2.5 MW Fuhrlander 2500 wind turbines. The facility is expected to be in operation as early as March 2008, with an ultimate capacity planned in excess of 100 MW.
Exelon Generation Company, LLC, has signed a 20-year power purchase agreement with Epuron LLC for the energy produced at a Falls Township, Pa., solar energy facility. This power plant will be among the nationÃ¢â‚¬â„¢s largest solar photovoltaic generation projects. The 3 MW project is on 16.5 acres in Falls Township, Bucks County. Estimated annual production is 3,700 MWh. The solar energy plant is slated to open in the second quarter of 2008.
The Prairie State Energy Campus said it has entered into an agreement with Southern Illinois Power Cooperative to purchase a 125 MW equity share of Prairie State’s planned 1,600 MW supercritical coal-fueled power plant project. The announcement came after a unanimous opinion by a three-judge panel of the Seventh Circuit of the U.S. Court of Appeals denying a challenge by several environmental and conservation groups to an air permit issued by the Illinois Environmental Protection Agency more than a year ago for the nearly $3 billion project.
Vogt Power International Inc. was selected by Southern Power to supply the heat recovery steam generator (HRSG) and associated equipment for the Orlando Utilities Commission’s Curtis H. Stanton Energy Center, in Orlando, Fla. Vogt will design, engineer, manufacture and deliver one duct-fired, three-pressure-level, natural circulation HRSG, to be installed behind a modified GE Frame 7FA gas turbine. The HRSG will be equipped with a multi-pollutant control system including an SCR system for NOX removal and CO catalyst for carbon monoxide reduction. The Stanton Energy Center, co-owned by Orlando Utilities Commission and Southern Power, will produce 285 MW of electricity for the Orlando area and is scheduled to begin operation in 2010.
SunEdison said that the Alamosa Photovoltaic Solar Plant in Alamosa, Colo., began generating 44 percent of its capacity, about 3.6 MW in late August for Xcel Energy. The first phase of the project broke ground in April 2007.
The Babcock & Wilcox Co. has opened a new Research Center in Barberton, Ohio, to concentrate on the next era of steam generation and environmental control technologies, including the capture of CO2 emissions from coal-fired power plants. The research center will test integrated combustion and environmental controls, evaluate advanced materials for super- and ultra-supercritical boilers, conduct further studies for flue gas desulphurization systems and mercury oxidation and enhance research in the complex science of coal combustion.
BrightSource Energy Inc. filed an application for construction with the California Energy Commission to build a 400 MW solar power field in the Mojave Desert in southern California. This is the first application filed in California for a solar plant since 1989.
The Long Island Power Authority ended a plan to install 40 wind turbines off the coast of Long Island after a report showed the costs of the $700 million project to be significantly higher than traditional forms of energy generation. Earlier estimates from LIPA consultants estimated energy from the wind development would cost between 6 and 9 cents per kilowatt hour, well above the 4.5-cent average LIPA has paid. Analysis showed the cost would approach 19 cents in the latter years of a proposed power contract.
Mesa Power filed documents with a Texas state agency to add 4,000 MW of wind-generated electricity to the power grid. The filing with ERCOT details plans for the project, which, when completed in late 2011, would be one of the world’s largest wind farm. Mesa Power said the project could have as many as 2,700 turbines on up to 200,000 acres in Roberts and adjacent counties in the Texas Panhandle. Mesa Power said it plans to build a power line.
The Ontario government has directed the Ontario Power Authority to procure a further 2,000 MW of renewable energy, including wind energy, in the province. The directive calls on the power authority to issue a request for proposals for an initial 500 MW of new renewable energy before the end of the year. Ontario’s current installed wind energy capacity is just over 415 MW, with an additional 1,200 MW under contract.
SaskPower is putting its clean coal project on the back burner, opting for more conventional and cheaper natural gas-fired generation, wind power and conservation to meet the province’s electricity needs to 2014. SaskPower Minister John Nilson told a news conference the 300 MW thermal generating station could not be built in time to meet rising electricity demands at a competitive cost. Cost of the coal-fired plant was initially estimated at C$1.5 billion but had increased to about C$3.8 billion. Instead, SaskPower will spend C$525 million to install 400 MW of natural gas turbines over the next five years. In addition, 100 MW of wind power will be added by 2012, as well as 50 MW of waste heat recovery projects and 20 MW of biomass by 2010.
The U.S. Environmental Protection Agency recently listed Units 1 and 2 at Ameren Energy Generating’s Newton Power Station as the second and third lowest emitters of nitrogen oxide (NOX) among all U.S. coal fired plants operating without selective catalytic reduction NOX removal equipment. In January 2007, Newton personnel, with technical support from equipment supplier Alstom, began NOX reduction program using process tuning, which adjusts boiler operating levels.
NRC regulators say they are weeks away from an anticipated flood of license applications for new reactors not seen since the 1970s. The NRC could receive combined construction and operating license applications for as many as 29 reactors at 20 sites, most in the South, over the next three years. The first could come as early as October 1, the start of the federal fiscal year. The NRC reportedly has hired more than 400 inspectors, engineers and examiners to handle the load. .
The Dow Jones Sustainability Indexes named Entergy Corp. to its Dow Jones Sustainability World Index and the Dow Jones Sustainability North American Index. Entergy was the only U.S. utility selected to the world index and one of 16 utilities chosen worldwide.