The price tag to build new power lines to bring wind power to Texas’ biggest cities could range from $3 billion to $9 billion, according to a report filed by the grid operator with state regulators.
Following legislation passed in 2005, the Texas Public Utility Commission began working to speed up construction of high-voltage transmission lines to handle a ramp-up of renewable power. Wind farms are located across sparsely populated west Texas, far from load centers in places such as Dallas, Houston and San Antonio.
After identifying the areas with the best potential for new wind generation, the commission ordered the Electric Reliability Council of Texas (ERCOT) to design routes to move 5,100 MW to 17,500 MW to the state’s big cities.
ERCOT said in its report, filed in April, that two scenarios to gather and transfer 12,000 MW on 345 kV lines could cost from $2.95 billion to $3.78 billion, depending on the number of lines built.
A more ambitious plan to bring as much as 18,400 MW to load centers could cost $4.93 billion. The most expensive plan, which would bring more than 24,000 MW of wind generation to the eastern half of the state, could cost from $5.75 billion to $6.38 billion. Using larger, 765-kv power lines could raise that cost to as much as $9 billion, ERCOT said.
Texas wind power: Is transmission relief just over the horizon?
A cover story in the January 2007 issue of Power Engineering magazine (“The Coal-Wind Connection”) explored the idea behind creating so-called competitive renewable energy zones (CREZs) in Texas. Under CREZ, zones were to be identified having at least 1,000 MW of renewable energy resources. New transmission corridors then would link those zones to power markets in ERCOT. The zones were to be determined based on optimal diversity, fuel savings, reliability and emission reductions.
CREZs were identified in wind-prone west Texas and between Corpus Christi and Galveston. The latter two sites encountered local opposition to resource development. New transmission and enhancements would bring wind power into load centers in central, north and east Texas.
The Texas approach appealed to the wind industry. The state reportedly received a $10 billion investment guarantee from wind energy developers in exchange for the state’s assurance that necessary power transmission lines would be built.
Transmission companies interested in building new lines include units of Babcock and Brown, ITC Holdings Corp., FPL Group, AES, BP Wind, Shell WindEnergy, CenterPoint Energy and privately held Sharyland Utilities and Energy Future Holdings Corp.–David Wagman and Steve Blankinship
Coal Study Moves Ahead with Calif. OK
Southern California Edison (SCE) will spend $50 million over two years to study the feasibility of combining several advanced coal technologies at full commercial scale. The decision to move forward with the technology assessment followed approval of the plan by the California Public Utilities Commission.
SCE’s advanced coal generation study combines for the first time the following elements:
- A chemical process that captures as much as 90 percent of the carbon dioxide in domestic coal.
- Producing a mostly hydrogen fuel and emitting 10 percent of the carbon released by an integrated gasification combined-cycle coal project without carbon capture.
- Burning the hydrogen in a highly efficient, combined-cycle generation system.
- Sequestering the carbon dioxide in a deep saline formation or a depleted oil formation to create enhanced oil recovery.
- The use of these technologies in a full-scale, 600 MW commercial generation facility.
The regulatory approval is the second major endorsement in the past six months of SCE’s proposed feasibility study. The DOE last October announced a grant of more than $65 million to SCE and other participants in the Southwest Regional Partnership for Carbon Sequestration to conduct one of the nation’s first large-scale carbon sequestration studies. The partnership plans to inject several million tons of carbon dioxide into the sandstone formation in the southwestern United States.
As part of the process, coal and water would enter a gasifier where the coal would be converted to a fuel gas. The gas then would undergo further processing to remove sulfur, mercury and carbon dioxide resulting in low-emission hydrogen fuel. Carbon dioxide extracted during the process would be sequestered in underground geologic formations. The hydrogen would be piped to gas turbines to generate electricity. As a last step, exhaust heat from the gas turbines would create steam to drive additional turbines.–David Wagman
PG&E Repowering Project Set to Begin
Wärtsilä North America Inc. began detailed engineering and manufacturing on a 163 MWe gas-fired power plant for Pacific Gas and Electric Co. (PG&E). Plant construction could begin later this year and be completed in the fall of 2009. Construction cost is estimated at $250 million, or around $1,500/kW.
In April 2006 Wärtsilä was selected to deliver the power plant to PG&E. The project has been subject to the approval of the California Public Utility Commission and environmental permits issued by the California Energy Commission. All approvals have now been received.
Coming to PG&E: A Wärtsilä 18V50DF dual-fuel engine.
The plant will be in Humboldt County near Eureka in northern California and is expected to enter commercial operation by mid-2010. When compared to the existing 50-year-old PG&E plant at the site, the new facility will be 33 percent more efficient with 85 percent fewer ozone forming compounds and a 34 percent reduction of greenhouse gas emissions production.
The new facility will consist of 10 Wärtsilä 18V50DF lean-burn dual-fuel engines delivered on an engineering, procurement and construction basis. The engines will be fueled by natural gas and will be capable of using ultra-low sulphur diesel as a back-up during times of natural gas curtailment.
The plant is designed as a load-following and daily cycling facility to meet electric generation load and reliability requirements in PG&E’s transmission constrained Humboldt service area. The project replaces existing Units 1 and 2 (105 MW combined capacity) consisting of natural gas- and oil-fired steam turbine-generating units. Two diesel-fired mobile emergency power plants rated at 15 MW each also will be replaced.
The service area relies extensively on local generation resources due to power import constraints and service interruptions in the 115 kV transmission system.
The reciprocating engines being installed are similar to a conventional automobile engine, containing 18 cylinders in a V-formation. During normal operation, the engines use natural gas as fuel, with a small amount of diesel fuel injected through a micro-pilot system to ignite the natural gas in the cylinders. During times of natural gas disruption or curtailment, the engines use diesel fuel supplied through a separate, conventional injection system. The dual-fuel technology is capable of operating at up to 48 percent efficiency. Auxiliary equipment includes inlet air filters, oxidation filters, gas exhaust silencer stacks, air radiator cooling array, generator step-up and auxiliary transformers and emergency diesel fuel storage tanks.
Air emissions from the proposed facility would be controlled using best available control technology applied to each engine’s exhaust. Each system would consist of a selective catalytic reduction unit for oxides of nitrogen (NOX) control and an oxidation catalyst unit for carbon monoxide (CO) and volatile organic compound (VOC) control.
The plant would be connected to PG&E’s existing switchyard via 13.8 kV cables and bus work from the generator circuit breakers to new step-up transformers and then via two 60 kV tie lines and one 115 kV tie line into the switchyard. Normally, four of the units would feed into the 115-kV line. The remaining six units would feed into the 60 kV lines. Switchyard improvements would include replacing the existing 60 kV and 115 kV circuit breakers and replacing a 115 kV steel lattice tower with three steel poles.
Natural gas would be supplied via an onsite 10-inch-diameter, high pressure natural gas pipeline owned and operated by PG&E. The natural gas would flow through gas scrubber/filter equipment, a gas pressure control station and a flow regulating station prior to entering the reciprocating engines.
The plant proposes using around 2,400 gallons of water per day (2.7 acrefeet/year) on average for cooling or other industrial purposes. The engines would use an air radiator cooling system in a closed loop system (similar to automobiles). Raw water for industrial processes and site landscape irrigation would be supplied from PG&E’s existing ground water well via a direct connection to an onsite six-inch-diameter water pipeline.
The project is expected to take about 18 months for construction and startup testing and could begin commercial operation as early as fall 2009, if there are no delays.
The power plant would be capable of operating both in load following mode to meet local system demand and reliability requirements and in daily cycling mode, where the plant could operate up to maximum capacity during the day and totally shut down at night or on weekends. The planned life of the generating facility is 30 years, but could be extended if the plant is still economically viable.–David Wagman
Plans Advance for Large-scale Hydro
Manitoba Hydro took a step closer to building a new set of hydroelectric dams in the northeastern corner of the Canadian province. The firm plans to build two new dams on the Nelson River, the 620 MW Keeyask project and the 1,250 MW Conawapa generating station, at a combined cost of about C$8.5 billion (US$8.44 billion).
The new-build effort would support Manitoba Hydro’s newly signed agreement with Wisconsin Public Service to export up to 500 MW of hydroelectric power over 15 years starting in 2018.
Electricity exports generated C$592 million (US$585 million) in revenues for Manitoba Hydro last year. Exports could produce C$5.5 billion (US$5.4 billion) in revenues over the next 10 years. The Wisconsin Public Service deal is worth a reported C$2 billion (US$1.98 billion). Manitoba Hydro’s export sales, on average, account for more than 40 percent of its electricity revenues.
The hydroelectric company recently signed a separate so-called “term sheet” agreement with Minnesota Power to provide 250 MW of hydro power over 15 years starting in 2020, as well as surplus energy starting this year. In early 2007, Manitoba Hydro and Wisconsin Public Service renewed a 100 MW export agreement.
To meet the 2018 export target date, project construction must start within the next four to five years, Hydro officials said. The deal still requires regulatory approval on both sides of the border. The projects also face what could be lengthy public reviews over environmental issues.
500 MW of hydro power exports to the U.S. if Manitoba Hydro builds new capacity and transmission.
The environmental review process can take years; it took fives years for the federal government to complete its review of the Wuskwatim hydro dam, as well as two years of review by Manitoba’s Clean Environment Commission.
One part of the newly announced hydro package is a proposed high-voltage direct-current line that will need to be built. The so-called BiPole III line has been the subject of controversy since provincial officials announced last year that it would take a longer, more expensive route through the west side of the province, rather than cutting a shorter route through boreal forest on the east side of Lake Winnipeg. The power being generated would originate in the northeast of Manitoba. It would leave Manitoba through a converter station to be built east of Winnipeg.
Opponents say the Wisconsin agreement highlights the need to rethink the western Manitoba route the province intends to use for what would be Hydro’s third high-voltage direct-current transmission line.
Provincial officials said they don’t plan to change their minds on the transmission line location.–David Wagman
The Face Behind the Advertisements
Chesapeake Energy’s Aubrey K. McClendon
It should come as no surprise that Oklahoma City-based Chesapeake Energy’s anti-coal plant activities, aimed at proposed plants in Texas, Oklahoma and Kansas, have riled the coal industry and companies that want to build new coal-based capacity. But its high-profile stance may not be sitting well with others in the natural gas industry, either.
Last year, the Natural Gas Council publicly distanced itself from ads paid for by Chesapeake, although Chesapeake wasn’t identified as the advertiser. The ads showed people with blackened faces and a caption that read “Face it: Coal is filthy.”
Aubrey K. McClendon, Chairman of the Board, CEO and Director of Chesapeake, the nation’s largest independent natural gas producer/developer and the third largest overall, is the driving force behind those ads. He also established the American Clean Skies Foundation, a pro-natural gas organization that McClendon insists in not anti-coal.
In an interview with Power Engineering magazine, McClendon said that it became clear to him two years ago that “right in the heart of gas country a bunch of coal-fired power plants were being proposed.” If built, those plants would “harm our environment and fail to use a product that is in abundance right here in our own back yard.”
The event that drove him to action was the plan by Future Energy Holdings (then known as TXU) to build 11 coal plants just as Chesapeake and others were discovering the natural gas resource potential in the Barnett Shale geology of north Texas.
“Texas gas production was on the upswing and I thought it was a curious decision in a curious place at a curious time,” he said of the coal plant proposals.
In talking with TXU, McClendon said he learned that natural gas was seen as an unreliable and expensive fuel. He said the run-up in natural gas prices after Hurricane Katrina in 2005 was the utility’s primary reason for re-embracing coal. Around the same time, Oklahoma Gas & Electric and Public Service Company of Oklahoma announced plans for a supercritical coal plant in Oklahoma and Sunflower Cooperative announced plans to build two supercritical units at its Holcomb plant in Kansas.
McClendon also saw a void in the discussion around the possibility that natural gas could be produced in large amounts from shale such as the Barnett formation. “Public policy makers and utilities were making decisions based on bad information.” McClendon said.
Chesapeake hired a Los Angeles advertising firm, which developed a series of ads. For its Texas ad campaign, Chesapeake helped pay for more than $1 million for the “coal is filthy” ads. Other ads urged attendance at an anti-coal rally at the state capitol sponsored by the Lone Star Chapter of the Sierra Club.
In Oklahoma, Chesapeake developed a campaign opposing the Red Rock coal plant proposal. State regulators subsequently voted 2-1 to reject the utility’s request to build it. Chesapeake also funded a Kansas group called Know Your Power, which opposed Sunflower Electric Power Corp.’s Holcomb proposal.
“Coal advocates say we’re the Saudi Arabia of coal,” McClendon said. “If that’s true, coal prices shouldn’t have doubled in the past year. The cost of coal power plant construction is up at least 50 percent or perhaps even by a factor of two and the political climate has changed,” he said. “The momentum has clearly changed back to cleaner fuels,” which McClendon defines as nuclear, wind, solar and natural gas.
McClendon said he accepts the fact that coal plants will continue to be built and provide much of the nation’s electricity. “But if you’re choosing coal because you think we’re running out of natural gas, you’re wrong.”
He said the natural gas industry is finding enough natural gas to lift production at least 5 percent a year “indefinitely.” That should enable gas prices to remain largely where they are today, which, McClendon said, is “about the cheapest in the industrialized world.” It’s a message that Chesapeake–and Aubrey McClendon–seem intent on promoting any way they can.–Steve Blankinship
Kiewit Corp. recently formed Kiewit Power, which brings together two subsidiaries: Kiewit Industrial Co. (now Kiewit Power Constructors Co.) and Bibb and Associates Inc. (now Kiewit Power Engineers Co.). Kiewit Industrial Co. began operations in 1951. Bibb and Associates was acquired in 1998.
Active Power Inc. received an order for its CleanSource UPS (uninterruptible power supply) 1500iC system. The system will be deployed at a regional healthcare facility in the Netherlands.
UniStar Nuclear Energy said it is partnering with Accenture to develop an information technology platform, called “Galaxy”, capable of supporting the data needs of a potential new fleet of nuclear power plants. Galaxy is expected to enable nuclear plant partners, suppliers and customers to meet and accelerate project work schedules and budgets through cycle time reductions. Galaxy will be delivered in phases over the next several years. The initial phase is expected to be delivered in the coming months and will be focused on the design of the U.S. EPR.
Basin Electric Power Coop. formed PrairieWinds ND1 Inc. to develop wind power. PrairieWinds is expected to begin operating a 115.5 MW wind project near Minot, N.D., by 2010.
Florida Power & Light Co. asked Florida regulators for approval to build a 1,219 MW combined cycle natural gas-fired power plant at the company’s West County Energy Center in Palm Beach County, where two units are already under construction.
Public Service Electric and Gas Co. won approval from New Jersey state regulators to begin offering $105 million in loans to help finance the installation of solar systems on homes, businesses and municipal buildings. Initially, the program will be available to non-residential customers only. The program will support development of 30 MW of solar power, which will meet about 50 percent of the renewable portfolio standard requirements in PSE&G’s service area for 2009 and 2010. Loans would cover 40 to percent of a solar installation project’s cost. Borrowers repay principal, plus interest, over 10 years for residential customers and 15 years for all other borrowers.
Ontario-based Bruce Power estimates the cost of returning two idle reactor units to service at between C$3.1 billion and C$3.4 billion (US$3.06 billion to US$3.36 billion), up from an original 2005 cost projection of C$2.75 billion (US$2.72 billion). The consortium said that after a “comprehensive review” it remains confident that units one and two can be returned to service “close to the planned dates of 2009 and early 2010,” adding 1,500 MW to the Ontario
Federal regulators accepted an application from Entergy Corp. to build a nuclear reactor at the Grand Gulf site near Port Gibson, Miss. Entergy’s application is the seventh combined license application accepted for review by the Nuclear Regulatory Commission, which expects 10 more applications this year. Entergy submitted its application on Feb. 27. Entergy wants approval to build and operate a simplified boiling water reactor at the site. The NRC also currently is reviewing that design for possible certification. The agency expects to complete that review in mid-2010.
The AFL-CIO Building and Construction Trades Department (BCTD) and Bechtel Construction Co. agreed to negotiate a labor contract for Bechtel’s involvement in a proposed third reactor at Calvert Cliffs Nuclear Power Plant in Maryland. Under the agreement, to be signed by the end of the year, the BCTD will provide qualified, skilled craft workers to the Calvert Cliffs project and Bechtel will provide fair wages and fringe benefits for all craft workers. As a result of the agreement, BCTD intends to build the first new generation AREVA EPR as a part of the Calvert Cliffs project, pending approval of loan guarantee contracts by the federal government.
Xcel Energy asked the Nuclear Regulatory Commission to extend its current 40-year operating licenses for the Prairie Island site to 60 years. Xcel is also submitting a request to increase the power generation of each reactor by 80 MW, bringing the two reactor’s total capacity to 1,240 MW. Without the extension, Xcel’s licenses on the Prairie Island reactors (each of which currently has a capacity of 538 MW) will expire in 2013 and 2014. The NRC has reviewed 48 of the country’s 104 reactor operating licenses and is not expected to make a decision on Prairie Island until 2010.
The U.S. Department of Energy (DOE) announced plans to issue loan guarantees in two stages this summer for up to $38.5 billion for projects that use advanced technologies that avoid, reduce or sequester emissions of air pollutants and greenhouse gases. This marks the second and third rounds of the DOE’s Loan Guarantee program. DOE plans to issue its second round of guarantees no later than June 2008 for efficiency, renewable energy and electric transmission projects (up to $10 billion); nuclear power facilities (up to $18.5 billion); and nuclear facilities for the “front-end” of the nuclear fuel cycle, including uranium enrichment (up to $2 billion). Later this summer, DOE intends to issue a third loan guarantee for advanced fossil energy projects (worth up to $8 billion).
Entergy Corp. selected Enexus Energy Corp. as the new name of the independent, publicly traded nuclear power company it plans to spin off later this year, and EquaGen L.L.C. as the name of the new joint venture Entergy and Enexus will co-own and which will operate the six nuclear reactors to be spun off. Last November Entergy announced plans to separate the non-utility nuclear business from its rate-regulated utility business through a tax-free spin-off of the non-utility nuclear business.
Construction & Contracts
Thermal Engineering International Inc. was awarded a contract by Siemens Power Generation Inc. to supply the feedwater heaters for Longview Power’s supercritical cycle pulverized coal-fired mine-mouth generating facility in Maidsville, W.Va. TEI will supply eight feedwater heaters: five low pressure and three high pressure units. Upon its completion in the spring of 2011, Longview will generate 695 MW (net) of electricity.
Curtiss-Wright Corp. received orders from Westinghouse Electric Co. to provide four Generation II reactor coolant pumps and pump seals supporting the completion of Unit 2 of the Tennessee Valley Authority Watts Bar nuclear power plant as well as long-lead materials for drive rods for Units 1 and 2. Curtiss-Wright’s Electro-Mechanical Corp. will engineer and manufacture the pumps, seals and drive rods. Watts Bar Unit 2 is approximately 60 percent complete. In August 2007, TVA’s board of directors approved a five-year, $2.5 billion plan to finish the unfinished unit.
South Carolina Electric & Gas Co. reached an agreement with Westinghouse Electric Co. and The Shaw Group Inc. authorizing the purchase of long-lead-time materials for up to two new Westinghouse AP1000 nuclear electric generating units. The move keeps the company on schedule to have a plant online by 2016. SCE&G also filed a letter of intent with the South Carolina Public Service Commission and the South Carolina Office of Regulatory Staff indicating that the company plans to file a combined application under the Base Load Review Act, as required under state law. On March 31, SCE&G and Santee Cooper submitted an application with the Nuclear Regulatory Commission for a combined construction and operating license (COL). Once approved, the COL would authorize the companies to build and operate up to two new nuclear reactors at the utilities’ existing V.C. Summer Nuclear Station site in Jenkinsville, S.C.
Progress Energy Florida, a unit of Progress Energy, said it signed a letter of intent with Westinghouse Electric Co. and The Shaw Group Inc.’s Power Group authorizing the purchase of long-lead-time materials for up to two Westinghouse AP1000 reactors at a site in Levy County, Fla.
Marsulex Environmental Technologies has been awarded a contract by Minnkota Power Cooperative to design, supply and install a wet flue gas desulfurization system and lime preparation system at its lignite-fired, Milton R. Young Station near Center, N.D. MET will supply technology, engineering and FGD equipment for Unit 1, rated at 250 MW, and will also design, supply and erect the lime storage, handling and preparation system. Start-up of the FGD system is scheduled for April 2011.
Babcock Power Environmental Inc. was awarded a $100 million contract to supply the wet flue gas desulfurization systems (WFGD) for South Carolina Electric & Gas’ coal-fired Wateree Station and Williams Station, both in South Carolina. The contract includes the supply of two WFGDs complete with absorber island, limestone preparation and gypsum dewatering systems, with complete flue duct and structural steel components to integrate the WFGD system into the existing power plants. The contract is scheduled for completion in 2009.
DJ Power Partners, a joint venture between Kiewit and TIC-The Industrial Co., signed a contract with PacifiCorp for the full engineering, procurement, construction and startup of a new dry flue gas desulfurization system and baghouse at PacifiCorp’s Dave Johnston Power Plant near Glenrock, Wyo. Work will be completed on Units 3 and 4, two existing 230 MW and 330 MW coal-fired units. The Babcock & Wilcox Co. will supply the FGD systems, including absorber areas and a common reagent preparation system. Unit 3 is expected to be put into operation in 2010 and Unit 4 in 2012.
Fluor Corp. said it will provide construction and commissioning support to Luminant for a $100 million-plus contract for air quality control upgrades on its Sandow Plant Unit 4 in Texas. The Sandow Steam Electric Station Unit 4 is a lignite-fueled generating unit owned and operated by Luminant. In addition to this new contract, Fluor has provided front-end design and detailed engineering for this selective catalytic reduction project. Fluor is also providing engineering, procurement and construction services for selective non-catalytic reduction and activated carbon injection projects at Luminant’s Sandow, Martin Lake, Monticello and Big Brown sites. Engineering began in May 2007, with an estimated completion date of May 2010. Site mobilization occurred in January 2008, with a tie-in outage scheduled for February to April 2010.
Pacific Gas and Electric Co. received approval from the California Energy Commission to build its 660 MW Colusa natural gas-fired generating station. The plant will be next to an existing PG&E natural gas compressor station, a 230 kV transmission line and natural gas transmission. The station will use dry cooling technology and will have no water discharge. PG&E expects construction to begin this spring, with the facility scheduled to begin commercial operation in the summer of 2010.
Korea Electric Power Corp. signed an agreement to build and operate a $500 million, 240 MW coal power plant in the Dominican Republic. The plant would cost the equivalent of $2,080/kW. The plant would replace a plant currently operated on fuel oil. The agreement comes as the country aims to use more coal for power generation due to rising global oil prices. Construction is expected to begin next year and conclude by 2011
Mergers & Acquisitions
TransCanada Corp. plans to buy from National Grid plc control of the 2,480 MW Ravenswood Generating Facility in Queens, N.Y. for US$2.8 billion (or $1,129/kW) plus closing adjustments (also see page 6). Ravenswood is a gas- and oil-fired generating facility consisting of multiple units employing steam turbine, combined cycle and combustion turbine technology. Ravenswood has the capacity to serve approximately 21 percent of the overall peak load in New York City.
Tennessee Valley Authority agreed to buy a three-unit, 810 MW combined-cycle combustion turbine facility owned by Southaven Power LLC located in Southaven, Miss. The utility will pay $461.3 million, or $570/kW, for the natural gas-fired plant that was valued at $490 million, or $605/kW in 2001. TVA will also pay $5 million to Southaven in connection with the termination of an operation and maintenance agreement currently held by a Southaven affiliate. Southaven is a wholly owned indirect subsidiary of Cogentrix Energy LLC.
U.S. Geothermal Inc. contracted with Michael B. Stewart and Empire Geothermal Power LLC to acquire a 3.6 MW geothermal plant and roughly 28,358 acres of geothermal energy leases and certain ground water rights in Nevada. The power plant, located north of Reno, Nev., includes four binary cycle units, a wet cooling tower and nine geothermal wells developed in a proven geothermal reservoir. The transaction purchase price is $16.62 million and includes approximately 18,000 acres of undeveloped U.S. Bureau of Land Management geothermal leases as well as the leases associated with the
Maxim Power Corp. is buying the Pittsfield Generating Co. and its 170 MW power plant in Pittsfield, Mass. from affiliates of GE Energy Financial Services for $52.9 million, or $311/kW. The facility is a 170 MW combined-cycle, dual-fuel power plant that consists of three combustion turbine generators, three separately fired heat recovery boilers and an extraction/condensation steam turbine generator. The project began commercial generation September 1, 1990. The purchase is expected to close by early in the third quarter and is subject to approvals by the Federal Energy Regulatory Commission, the U.S. Environmental Protection Agency and other customary closing conditions.
Tenaska Capital Management LLC, a unit of Omaha-based Tenaska Power Fund LP, announced the sale of Holland Energy, a 665 MW generating station in Illinois, to Indiana electric cooperatives Wabash Valley Power and Hoosier Energy. TPF acquired Holland Energy from Constellation Energy in 2006. The natural gas-fueled facility is a combined-cycle combustion turbine plant that generates electricity for the Midwest Independent System Operator grid.
The transaction is expected to close by January 2009.
Nevada Power Co. reached an agreement with Reliant Energy Inc. to buy Reliant’s Bighorn Generating Station, a 598 MW natural gas-fired, combined-cycle power plant 35 miles from Las Vegas, Nev. The Sierra Pacific Resources business unit will pay around $500 million for the plant plus related inventory. Commissioned in 2004, Bighorn uses dry-cooling technology. The companies expect the sale to be completed later this year following required approvals by the Public Utilities Commission of Nevada, the Federal Energy Regulatory Commission and other customary reviews.
People & Personnel
Andy White is now chairman of the London-based World Nuclear Association (WNA), following his election by WNA members last year. White was recently appointed to head General Electric’s New Energy Ventures business unit. White has 30 years of experience in the energy industry and most recently headed GE Nuclear and oversaw the creation of its alliance with Hitachi’s nuclear business. White also serves on the board and executive committee of the Nuclear Energy Institute.
Michael Liebelson is joining NRG Energy as executive vice president and chief development officer for low-carbon technology. Liebelson will oversee NRG technology initiatives including coal gasification, carbon capture and sequestration and biomass, and will lead NRG’s efforts to capitalize on other emerging energy technologies. In 1990, Liebelson co-founded LS Power Corp. Earlier, Liebelson was co-head of Commercial Union Energy Corp. and conceived and headed the independent power business for Ahlstrom-Pyropower. Liebelson received a BS in Chemical Engineering from the University of California at Berkeley and an MBA from the University of Pennsylvania.