Save Article Instructions
Close 

Reserve Margins Tighten in California and New England

The North American Electric Reliability Corporation’s (NERC) assessment of the ability for U.S. and Canadian power providers to meet electricity demand this summer indicates a reserve capacity margin reduction of almost 1 percent across all of North America. And while the projection calls for most of the U.S. to get through summer 2007 without major power shortages, it identifies several load centers - primarily in Southern California and New England-as places where there will be very little margin to absorb extreme weather or unforeseen loss of generating capacity.

NERC’s annual report released in May - The Reliability of the Bulk Power System in North America - projects that capacity margins for summer 2007 are expected to be comparable to 2006 and that “similar performance is expected overall.” Capacity margins are intended to mitigate the higher load levels associated with extreme weather events, unplanned loss of generation capacity while remaining able to provide sufficient operating margins.

Click here to enlarge image

Last summer, much of North America experienced extreme weather producing record peak demands from depleted available resources. Those conditions required implementing preplanned emergency procedures in some areas to maintain a balance between available supply and demand. Emergency alerts, public appeals, voltage reductions and shedding interruptible customer load were used to various degrees during the last week of July and the first week of August. But the only interruptions of firm customer load occurred due to heat-related problems on distribution systems and had no effect on the bulk power system. The report states that if extreme weather is experienced this summer and supplies become limited, emergency operating procedures similar to those used in 2006 are available.

Forecasted performance in the latest assessment is based on normal weather with a 50 percent chance of being higher or lower than expected. Last summer’s sustained widespread extreme weather (high temperature combined with high humidity) caused demand to exceed forecast by more than 3 percent. As a result, the 50/50 forecast for 2007 is about 1 percent less than the actual demand in 2006.

If similar extreme weather occurs this summer, it could threaten resource supply adequacy. Primary impacts of extreme weather include:

Emergency operating procedures are available to maintain a balance between supply and demand to ensure the reliability of the bulk power system when it is stressed. Many regions study extreme weather condition cases to understand and manage the associated risks.

Southern California, Connecticut and Boston

The amount of demand represented by customer interruptible demand and direct control load management (demand response) programs has increased since last year by more than 10 percent in Florida, 13 percent in other parts of the southeastern U.S., and almost 20 percent in the western U.S. and Canada. Many regions are studying the interdependence of fuel delivery and reliability, and improving coordination between fuel suppliers and generators.

NERC expects the Southern California region to have lower capacity margins this summer than most areas. That will require significant amounts of imported power causing transmission lines into the area to be heavily loaded much of the time. The California Independent System Operator (CAISO) has studied a number of operating reserve margin scenarios, including increased demand caused by extreme weather. CAISO has developed procedures to implement demand response programs and curtail interruptible loads to maintain required operating reserves in Southern California.

If extreme weather and loss of generating resources occur simultaneously, CAISO may also need to shed firm load to balance resources and demand. CAISO has analyzed the probability of implementing actions during these events to meet operating reserve margins. There is a 14 percent probability of using demand response programs, which are triggered when operating reserve margins fall to the 7 percent range and a 4.6 percent probability of using interruptible load programs, which are triggered when operating reserve margins drop to less than 5 percent. There is less than 3 percent probability of firm load shedding, triggered when operating reserve margins decline to 3 percent or below. That should only happen if extreme weather and a system contingency occur at the same time.

The transmission network into and within Southwest Connecticut has historically faced reliability concerns. The outlook for the area has improved for the summer of 2007 with the October 2006 addition of Phase 1 of the 345 kV Southwest Connecticut Reliability Project increasing import capability. Therefore, the combined ability of generating resources and transmission capacity to import power to the area should be adequate to meet demand under normal and most extreme weather conditions.

But resource adequacy studies show most of greater Connecticut constitutes a major load pocket in immediate need of resources, transmission improvements or both. Projected capacity margin for the summer is expected to remain negative. Over 200 MW of demand response resources in Connecticut have been added, which will help meet the area’s demand this summer. If local resources and imports into Connecticut are insufficient to meet the need, system operators would have to implement extreme measures including load curtailments in order to maintain local and regional system reliability.

Reliability within the Boston area also remains a concern. Stage 1 of the NSTAR 345 kV Transmission Reliability Project, intended to increase the import capability into the area, became operational in October 2006 and a second line was energized in May 2007, increasing the transmission import capability into the Boston area to 4,600 MW. Currently, a positive summer 2007 capacity margin is forecasted for the Boston area as a direct result of the NSTAR project.

In addition, regions of the United States with improved conditions since last summer include:


-Steve Blankinship

Geothermal Energy Barely Being Tapped

A leading developer of geothermal energy systems has told a congressional panel that continued federal funding of geothermal research is needed to tap possibly hundreds of thousands of megawatts of new geothermal energy to meet power needs in the United States.

Paul Thomsen, Public Policy Manager of Ormat Technologies, told the House Science Subcommittee on Energy and Environment in May that there is currently almost 3,000 MW of new geothermal capacity under development that will create more than 10,000 new jobs and about $7 billion in new capital investment. But much more is possible, Thomsen said.

Click here to enlarge image

The testimony comes in the wake of a proposal from the Office of Management and Budget to terminate federally funded geothermal research.

“The OMB proposal to terminate geothermal research is not only short-sighted, it just doesn’t make any sense,” said Thomsen. He spoke on behalf of Ormat as well as the Geothermal Energy Association (GEA). OMB has proposed zeroing out geothermal programs at the Department of Energy in its fiscal year 2007 and FY 2008 budgets.

“There are substantial needs for improvements in technology, resource information, and efficiencies for which federal research are vital,” said Karl Gawell, executive director of GEA. He supports a bill introduced by Rep. Gerald McNerney (D-CA) that would direct the Secretary of Energy to conduct a program of research, development, demonstration, and commercial application for geothermal energy. The legislation authorizes $400 million for geothermal research for fiscal years FY 2008 through 2012.

“Rep. McNerney’s legislation is urgently needed to ensure that federal energy programs work to tap the tremendous potential of our nation’s geothermal energy resources,” said Gawell. “Today, we are tapping only 3.5 percent of the estimated hydrothermal resource base.

Recent reports by the National Renewable Energy Laboratory and the Massachusetts Institute of Technology estimate that more than 100,000 MW of geothermal power is possible in the future, with continued research and development support.
-Steve Blankinship

U.S. Reported Lagging on Infrastructure Investment

The United States’ relatively low investment in virtually all aspects of mobility-related infrastructure - airports, public transit, railway systems, roads and bridges - as well as the electric power grid, represents an “emerging crisis” that will compromise the ability of the nation’s cities to compete globally, according to a new report co-published by the Urban Land Institute and Ernst & Young.

Click here to enlarge image

“Infrastructure 2007: A Global Perspective” offers what the report calls a status report on current and planned infrastructure investment and development in a variety of categories in countries worldwide, with a particular focus on the United States, China, Japan, India and Europe. The report discusses the evolving infrastructure market, including private and combination public-private systems for funding, construction, operations and management. Although focusing primarily on transportation, many of the report’s findings have broad significance for America’s electric power infrastructure as well.

“America is more of a follower and no longer a world leader when it comes to infrastructure,” the report states. It says the U.S. too often focuses on restoration, rather than rethinking the model and finding possible efficiencies. It also found a tendency to invest in existing infrastructure instead of the infrastructure that will be needed.

Among significant trends and issues noted in the report:


-Steve Blankinship

Supreme Court Ruling Could Hit AEP and Duke

A U.S. Supreme Court decision could have serious implications for at least two of the nation’s largest power providers and could affect many other U.S. utilities that operate coal plants.

In April, the Supreme Court vacated an earlier decision by the United States Court of Appeals for the 4th Circuit in the case of Environmental Defense versus Duke Energy Corporation. The Supreme Court opinion overturned rulings rendered unanimously by the 4th Circuit Court of Appeals that found an hourly emissions standard is appropriate when applying new source review (NSR) standards. Lower courts ruled that work commonly done to maintain and increase the efficiency of Duke coal plants in North Carolina and South Carolina between 1988 and 1999 did not increase the plant’s hourly emissions and therefore should not be subject to NSR review.

The Supreme Court considered only whether an hourly emissions standard was appropriate to use when triggering NSR. It did not review what constitutes routine repair and replacement activities under NSR.

The case stems from an effort that began in 1999, when the EPA filed a number of enforcement actions and reinterpreted NSR rules to eliminate the well-established trigger as to what constitutes a major modification at a power plant. The EPA contended that NSR can be triggered by common projects that maintain a facility’s operating capabilities but which do not increase the plant’s emission rate.

In a unanimous decision, the justices concluded that the federal government correctly argued that Duke Energy violated federal clean-air laws when the company modified eight of its coal-fired plants in North and South Carolina without first obtaining permits from the government. By doing so, the Clinton Administration charged in a 2000 lawsuit that Duke Energy had both extended the lives of those older plants and emitted more air pollution, which would have required them to obtain a permit first. The court rejected Duke’s contention that the changes in those plants were not major modifications and thus did not require permits.

Following the Supreme Court ruling, Duke Energy said it will continue to defend itself on the matter in the lower courts.

“We continue to believe we have solid defenses against the government’s claims and will show in the lower courts that our power plant projects were not subject to NSR,” said Marc Manly, Duke Energy’s chief legal officer. “Duke Energy’s emissions have been substantially reduced through other Clean Air Act requirements and state clean air laws,” he said. “The company has invested more than $1.5 billion to reduce nitrogen oxide emissions since 1998 and is investing nearly $3.5 billion more to further reduce nitrogen oxide and sulfur dioxide by 2010. The net result of these investments is reduction of sulfur dioxide and nitrogen oxide emissions by approximately 70 percent across Duke Energy’s five-state service area by 2010.”

The ruling also directly affects plants operated by Columbus, Ohio-based AEP and could potentially result in multi-million-dollar fines for the utility based on a lawsuit against AEP and nine of its oldest coal-fired plants including Muskingum River, Cardinal and Conesville. AEP modified those plants without first obtaining permits.

U.S. District Court Judge Edmund Sargus had delayed ruling on the AEP case until the Supreme Court decided the Duke Energy case. AEP has already spent $5 billion to install new air pollution control equipment on most of the plants named in the suit, but the judge could impose financial penalties on the company for not cleaning the emissions sooner.

“Obviously, we’re disappointed in the decision,” said AEP spokesman Pat Hemlepp. “Our lawyers are looking at it to determine what the impact will be on our existing case.”

AEP is trying to build integrated gasification combined cycle (IGCC) plants in Ohio and West Virginia that would capture and sequester carbon dioxide (CO2). Ohio utility regulators have already approved including a portion of the initial engineering study costs associated with the Ohio IGCC in the rate base. AEP is seeking inclusion of additional funding for recovery and is seeking rate recovery in West Virginia of engineering costs for the IGCC it hopes to build there. Following the commission’s approval of preliminary engineering costs for the Ohio plant, the Ohio Consumers’ Counsel and Ohio industrial energy users filed a lawsuit with the state’s public utilities commission challenging the inclusion. That suit is slowing the process. When originally announced in 2004, AEP hoped to have the Ohio plant built and online by 2010. In 2005, the company revised its time table, saying it hopes to have the Ohio plant operating “sometime in the first half of the next decade.”

In March AEP announced plans to expand its emission-reduction retrofits with the first commercial use of technologies to reduce CO2 emissions from existing coal-fueled power plants. AEP will install a post-combustion carbon capture technology that uses chilled ammonia developed by Alstom at AEP’s Mountaineer Plant in West Virgina next year. Following the validation at Mountaineer, AEP plans to install a similar system on one of the coal-fired units at its Northeastern Station in Oologah, Okla. That installation would be operational in 2011.

AEP has also signed an agreement with Babcock & Wilcox (B&W) for a feasibility study of oxy-coal combustion CO2-reduction technology. Following a pilot demonstration, AEP and B&W will select an existing AEP plant site for commercial-scale installation. The oxy-coal combustion technology is expected to be in service on an AEP plant in the 2012-2015 timeframe.

AEP’s CO2 retrofit plans are part of a larger strategy to address the company’s contribution to global concentrations of greenhouse gas emissions (GHG). AEP adopted an expanded climate change strategy as part of a new focus on corporate sustainability initiated in 2006 that includes efficiency improvements at its existing coal plants; adding 1,000 MW of wind generating capacity to its eastern fleet through purchase agreements; additional investments in domestic GHG offsets, including methane capture; increased investment in forestry offsets; and programs to offset emissions from its 11,000-vehicle fleet and corporate aircraft.
-Steve Blankinship

Workers Falling Off at Yucca Mountain

Employees at the Yucca Mountain permanent nuclear waste facility in Nevada are being laid off. Budget problems continue to face the nuclear waste program as U.S. Department of Energy (DOE) officials seek to assure Congress that the project is on a new track following setbacks and long delays.

Details of the scope and reasons for the layoffs were provided in testimony by Ward Sproat, director of the Office of Civilian Radioactive Waste Management as he delivered the program’s latest budget request to a House appropriations energy and water subcommittee. Lawmakers will soon begin writing an Energy Department spending bill for the federal government’s fiscal year that begins in October.

Sproat told lawmakers it was vital for Congress to allocate $494.5 million to carry out the latest schedule that calls for filing a license application to the Nuclear Regulatory Commission in June 2008 and a repository opening later in the next decade.

“We need all of it,” Sproat said. But he added that even with full funding it will be difficult to avoid job cuts later this year.

“If we get the full $494.5 million, that is still $50 million less than we are spending this year; so you are talking several hundred people facing layoffs,” he said.

The project this year is spending $444.5 million and is exhausting another $100 million in carryover funds from last year. Sproat told lawmakers he wants to meet deadlines for the license application and that other parts of the project may be set aside. “There will be substantial reductions, but we will get the license application completed on time,” he said.

The latest job losses hit employees at Bechtel-SAIC, the program’s chief operations contractor. A project spokesman confirmed about 60 layoff warnings were issued in March to administrative and clerical workers in accounting, public relations and other departments, and to technical writers who are not working on the license application. Two years ago, Bechtel laid off about 150 people.

Last summer, as many as 500 workers were issued job warnings, although many ended up transferring to the payroll of Sandia National Laboratories, which was assigned a larger role at Yucca Mountain.

Members of the House panel have traditionally supported full funding for Yucca Mountain. But in the Senate, Sen. Harry Reid of Nevada, among Yucca Mountain’s most powerful critics, has exercised control over its budget. House members have expressed impatience with the slow pace of Yucca Mountain and urged Sproat to speed it up if possible.

“I don’t understand why it is taking so long,” said Rep. John Doolittle of California. “It is disturbing. I recall Hoover Dam was built working seven days a week around the clock in around three years. We are so tied down by our bureaucratic systems.”
-Steve Blankinship

Methane from Dams Could Be a Power Source

Scientists from Brazil’s National Institute for Space Research, INPE, have published a study that suggests capturing methane produced by large-scale hydroelectric dams and using it to generate electricity.

Click here to enlarge image

Dr. Ivan Lima and his colleagues argue in their paper that large dams release about 104 million metric tons of methane into the atmosphere worldwide each year through reservoir surfaces, turbines and spillways.

The Brazilian research report suggests capturing methane from dam-created reservoirs and combusting it to produce electricity. Their research suggests that large hydroelectric dams release methane into the atmosphere because trees and other plants settle to the bottom when the reservoir is first flooded. This plant material decomposes without oxygen, allowing dissolved methane to build up. When water is drawn from deep below the reservoir’s surface and channeled through a dam’s turbines, the methane is released into the atmosphere.

The paper is the latest in a series of published research reports done over the past 15 years by various researchers. Most are based on measurements of methane and carbon dioxide emissions due to rotting organic matter in reservoirs. Most data collection began in 1993 and includes some 30 reservoirs, mostly in Brazil and Canada.

Scientists involved in researching the effects of so-called “reservoir greenhouse gas emissions” are split. One group asserts that reservoir emissions are lower than emissions from equivalent fossil fuel plants. The second group warns that reservoir emissions are much more significant than commonly assumed and that in the tropics they can exceed emissions from fossil fuel-fired power plants.

Methane is calculated to be about 21 times more powerful at warming the atmosphere than carbon dioxide. Methane’s relatively short atmospheric lifetime (about 12 years) along with its potency as a greenhouse gas make it a candidate for emissions reduction in the short term.
-David Wagman

U.S. Gets a “New” Nuclear Reactor

The U.S. now has 104 operating commercial nuclear reactors. The additional unit is the 1,155 MW Brown’s Ferry Unit 1 in Athens, Ala., owned and operated by Tennessee Valley Authority (TVA), the nation’s largest power provider.

In a sense, Browns Ferry Unit 1 is the nation’s newest commercial reactor. But in reality, Browns Ferry Unit 1 has been part of the U.S. nuclear fleet since the plant first went into commercial operation in 1975. However, shortly after the plant’s startup 32 years ago, a worker using a candle to check for air leaks ignited insulation located near the control room. Safety systems did not react properly and the resulting fire caused $10 million in damage and put the reactor out of service for more than a year. TVA shut down its nuclear program in 1985 over safety concerns, Nuclear Regulatory Commission (NRC) fines and whistleblower complaints. In doing so it scrapped three plants and delayed others. Finishing Watts Bar Unit 1 cost nearly $7 billion because of extensive rewiring and pipe rewelding.

Click here to enlarge image

TVA’s nuclear fleet started coming back to life in 1991 with the restart of Browns Ferry Unit 2, followed by the restart of Unit 3 in 1995. In 2002, TVA’s board approved returning Unit 1 to service, calling it the best business decision to meet customers’ long-term power needs. The utility provides power to 158 power distributors serving 8.7 million consumers in seven southeastern states. The restart decision was based on improved nuclear performance, increased power demand in TVA’s service territory and environmental considerations. The Unit 1 restart also benefited from lessons learned in restarting units 2 and 3. Total cost of the restoration and restart of Unit 1 was $1.8 billion.

“All three units at Browns Ferry are essentially alike now,” said TVA Acting Chief Nuclear Officer Preston Swafford. “We have new or refurbished equipment that is operated in the same manner on all three units, and our ongoing operations, maintenance, training and oversight programs can focus on sustaining high-quality performance to ensure the safe and reliable operation of Browns Ferry.”

TVA completed more than 4 million work hours preparing the engineering and design and more than 15 million work hours modifying, replacing and refurbishing systems and components. TVA installed modern digital instrumentation and controls, modern power supplies, replaced 200 miles of electrical cable and eight miles of pipe, replaced or refurbished the unit’s large pumps and motors and conducted more than 1,200 tests to show that Unit 1 meets all design and regulatory requirements.

“You could almost point to Browns Ferry Unit 1 as really the beginning of nuclear energy’s rejuvenation in the United States,” said Scott Peterson, vice president of the Nuclear Energy Institute. Growing demand for electricity and concern over global climate change are propelling a nuclear renaissance. The Department of Energy estimates 50 new reactors will be needed by 2030 to keep pace with growing power demand and offset plant retirements. -Steve Blankinship

Blown Out of Proportion?

Those skeptical of wind power can cite plenty of reasons, from the capital cost of wind turbines compared to comparable capital costs from “more conventional” power sources to the fact that they can only produce annual capacity factors in the range of 30 to 40 percent.

Now a Canadian utility, which boasts one of the largest wind turbine portfolios in the world, has decided it has too much wind generating capacity.

Enmax Corp. has announced it will build a 1,200 MW gas-fired plant in Southern Alberta to help boost grid reliability after the region’s aggressive expansion into wind energy made it vulnerable to power disruption.

“We now have so much windpower generation that we need to fall back on reliable sources of power,” said Peter Hunt of Enmax. “The problem with wind power is that the wind doesn’t blow all the time, so the greater the percentage of the system depends on wind, the more vulnerable to disruption the system becomes when the wind stops blowing.”

The gas-fired plant, which would cost about $2 billion (Canadian), would produce enough power to supply two-thirds of Calgary’s electricity needs.

Alberta expanded into windpower generation aggressively since deregulating its electricity industry eight years ago. With more than 4 percent of its power coming from wind farms in the southern part of the province, it leads Canadian provinces in the amount of green energy is uses.

But last year, the Alberta Electric System Operator (AESO) - the provincial grid’s management entity - banned construction of any more wind farms until reliability issues are resolved. Despite the fact that wind is environmentally friendly, the typical wind farm in Southern Alberta makes wind only 35 percent of the time.

Warren Frost, AESO’s vice-president of operations and reliability, said the big gas-fired plant station should solve some of the grid’s variability challenges.

“It’s good news for Alberta in terms of getting another source of generation,” he said. “Alberta is continuing to grow at a phenomenal rate and another major investment in the generation of supply is a good thing.”

Enmax says the gas-fired plant will be located close to wind capacity so it can quickly pick up the load when the wind dies down. Enmax hopes the new power plant will firm up the transmission grid so more wind farms can be developed in the future. Alberta is expected to require up to 3,800 MW of additional wind capacity over the next 10 years.-Steve Blankinship

Biomass Idea Grows on Minnesota Power

Minnesota Power Company, which last year announced that biomass will be a significant part of its overall program to add renewable energy to its generation portfolio, has developed a short list of candidate biomass projects.

Click here to enlarge image

Multiple biomass opportunities were screened to identify the most economically feasible projects. The project finalists, located within existing Minnesota Power facilities as well as at other regional customer sites, will now undergo detailed due diligence.

The short list of projects from Minnesota Power’s Biomass Initiative includes:

Electricity from biomass is produced by combustion of material such as wood waste and forest residue and is seen to have fewer environmental impacts when compared with other fuels such as coal. Minnesota legislation passed this year requires all electric utilities in the state to generate 25 percent of its energy using renewable fuel by 2025.

The utility said it is working with other stakeholders in the region to develop the most viable projects and developing the supply chain of available biomass resource to meet the generation needs of biomass initiative. Minnesota Power will submit final plans regarding biomass and other renewable energy options under study as part of its integrated resource plan filing later this year. -Steve Blankinship

Coal and Water Make Cheap Juice

Coal and water mix well to make low-cost power. At least that would appear to be the case after looking at the latest U.S. Energy Information Administration (EIA) report showing that in 2006, Idaho households paid 6.12 cents/kWh, the lowest residential cost for electricity in the U.S. West Virginians paid 6.32 cents/kWh. Residents of Washington state paid 6.81 cents and Utah residents paid 7.61 cents. At the high end of the electric power cost spectrum, the EIA reported that Hawaiians pay an average 23.36 cents/kWh.

Click here to enlarge image

Historically, Idaho has long been among the lowest-cost states for electricity. A spokesman for Idaho Power credited the state’s historic low power prices to a generation portfolio based upon hydroelectric power and coal. West Virginia owes its low cost almost exclusively to coal-fired generation, as does Kentucky, while Washington state enjoys an abundance of hydro. Like Idaho, Utah’s low prices are tied to a combination of coal and hydro.

An important lesson emerges from examining the historic electric power cost curve in Idaho. Idaho incurred a short-lived price jump about 20 years ago upon completion of two coal plants that today make low-cost power. Rates peaked at about 8.5 cents/kWh in 1985 after Rocky Mountain Power, then known as Utah Power, completed construction of its Huntington and Hunter coal-fired plants and started passing along the costs of those plants to customers.

The two coal plants laid the groundwork for the 30 percent decline in electricity rates that took place between 1990 and 1997, said Dave Eskelsen, a spokesman for Rocky Mountain Power. He said that most customers didn’t notice their rates going down because it was gradual, starting at 1 percent to 2 percent per year.
-Steve Blankinship

Construction & Contracts

Black & Veatch has been selected by Gulf Power Company to provide detailed engineering, procurement and construction support for the addition of a CT-121 wet flue gas desulfurization system at Plant Crist Station in Pensacola, Fla. Black & Veatch was selected to do the conceptual engineering design of the scrubber project in 2006. The scrubber installation phase is expected to be completed by the fall of 2009.

Babcock & Brown has agreed to buy 118 Mitsubishi 2.4 MW MWT95/2.4 wind turbines for delivery in 2008. The units will be installed at Babcock & Brown projects in the southwest United States.

Southwestern Electric Power Co. awarded The Shaw Group Inc. a $700 million engineering, procurement and construction contract to build the $1.3 billion John W. Turk, Jr. Power Plant, a 600 MW coal-fueled station at Fulton, Ark. SWEPCO is seeking regulatory approvals to build the plant from Arkansas, Texas and Louisiana authorities. The plant would use ultra- supercritical pulverized coal combustion technology. Turk is scheduled to be completed in mid-2011.

Babcock & Wilcox (B&W) has received a contract for engineering, materials, construction, start-up and commissioning of environmental equipment at Allegheny Energy’s Fort Martin Power Station near Maidsville, W. Va. For its share of the plant’s total $550 million project, B&W will perform work on Fort Martin’s two 550 MW supercritical coal-fired boilers.

Southern Co. said it has decided not to partner with Duke Energy Corp. on the proposed Lee Nuclear Plant near Cherokee, S.C. Duke plans to buy Southern’s 500 MW share of the 2,200 MW plant. A purchase price was not immediately disclosed. Duke reportedly would have to pay Southern for its share of the planning and development costs already spent this year on the project. Duke earlier estimated those costs would be about $125 million for the whole year. Not all of that has been spent, and Southern’s share would be about a quarter of the costs.

Sargent & Lundy has been chosen by NRG Energy to engineer expansion of the South Texas Nuclear Project that would add two additional units producing 2,700 MW.

Babcock Power Inc. subsidiary Babcock Power Environmental Inc. and CH2M Hill will team up for the engineering, procurement, construction and startup of a new emissions control system for the Gainesville Regional Utilities Deerhaven Unit #2 Power Plant in Florida. The new emissions control system includes a selective catalytic reduction system, a Turbosorp circulating fluidized bed dry scrubber and a Hamon fabric filter. The total project award is nearly $119 million.

Mergers & Acquisitions

URS Corp. and Washington Group International Inc. have signed a definitive agreement for the acquisition of Washington Group by URS in a cash and stock transaction valued at approximately $2.6 billion. The transaction will combine two global engineering and construction companies, expand the capabilities of both firms and capitalize on their positions in power, infrastructure and environmental management. Based on previously issued guidance, the companies would have combined 2007 revenues of approximately $8.6 billion. In addition, the companies would have had combined 2006 EBITDA (earnings before interest, taxes, depreciation and amortization) of $425 million and total backlog exceeding $11 billion, as of March 31, 2007. If combined today, the companies would have projects in more than 50 countries and would have more than 54,000 employees.

Columbus Southern Power completed the purchase of the Darby Electric Generating Station from DPL Energy, LLC, a DPL Inc. unit, for $102 million, or $212/kW. The plant is a natural-gas, simple-cycle facility with a nominal generating capacity of 480 MW and a summer capacity of 450 MW. The plant began commercial operation in 2001.

Wisconsin Power and Light said it plans to pay $94 million to buy the Neenah Generating Facility, a seven-year-old, 300 MW simple cycle gas-fired electric generating facility to replace output currently under a purchased power agreement with Calpine’s RockGen Facility. The purchase price equals around $313/kW. The facility is currently owned by Alliant Energy Resources, a non-regulated affiliate of WP&L. WP&L plans to buy the facility for the plant’s net book value.

NorthWestern Corporation,which does business as NorthWestern Energy, said that the Montana Public Service Commission has unanimously directed its staff to prepare a draft order denying NorthWestern’s sale to Babcock & Brown Infrastructure Limited.The draft order may be presented to the commission for a vote sometime in late June 2007. “We are obviously disappointed by this development,” said Mike Hanson, president and CEO. “However, we will wait until the written order is issued before deciding on our next steps. ” On April 25, 2006, NorthWestern and BBI announced that they had reached a definitive agreement under which BBI would acquire NorthWestern in an all-cash transaction at $37 a share.

GE Energy Financial Services has purchased a 20 percent interest in The ERORA Group LLC, a privately owned Louisville, Ky., company that is developing a 630 net MW integrated gasification combined cycle (IGCC) power plant in Henderson County. The Cash Creek IGCC facility will generate power and produce substitute natural gas using coal gasification technology. Construction is expected to begin in late 2007, with commercial operation planned in 2010/2011.

BP Solar said it won a bid to develop 4.3 MW of solar energy systems for seven Wal-Mart stores in California. BP Solar will sell all of the energy produced by the solar modules, as well as operate and maintain the systems. Wal-Mart will receive all of the renewable energy credits (RECs) associated with the energy output of the systems. Terms were not disclosed.

Energy sector consultancy Hill & Associates has acquired Wood Mackenzie in a merger that adds 25 coal professionals to Wood Mackenzie.

GE Energy Financial Services said it will buy the 517 MW Shady Hills power plant, near Tampa, Fla., from LS Power Equity Partners. Financial details were not disclosed.

Chevron said it would sell its stake in electricity producer Dynegy Inc. for about $940 million. The oil giant hired Goldman Sachs & Co to sell its 96.9 million Dynegy shares in an underwritten offering. Chevron owned its stake in Dynegy since 1996, when it combined its midstream, or pipeline, terminal and processing, businesses and assets with natural gas-marketer NGC Corp. to form what was then the largest natural-gas and gas-liquids wholesaler in North America.In April, Houston-based Dynegy merged with LS Power, a privately owned power plant investor. That deal gave LS Power a 40 percent stake in the company and reduced Chevron’s stake to about 11 percent from about 20 percent.

Atlas Energy Resources LLC said it reached an agreement to buy DTE Gas & Oil Co. for $1.225 billion in cash. DTE Gas & Oil is a unit of DTE Energy Company based in Traverse City, Mich.

Business Briefs

Duke Energy Corp. CEO James Rogers said the utility will move forward with plans to build a single coal-fired generator at its Cliffside power plant in western North Carolina. Duke sought a permit for two new 800 MW coal-fired units at its Cliffside Steam Station in May 2005. In February, regulators said they would allow the company to build one generator.

AmerenUE signed an agreement with UniStar Nuclear to help prepare a combined construction and operating license application (COLA) for filing with the Nuclear Regulatory Commission. AmerenUE and UniStar Nuclear need to submit the COLA to the NRC in 2008 to be eligible for incentives available under provisions of the 2005 Energy Policy Act.

The American Wind Energy Association said in its first quarter market report that the U.S. wind energy industry is on track to install over 3,000 MW of wind power generating capacity nationwide in 2007. Over 100 MW have newly come online in the U.S. so far this year and over 1,000 MW more are under construction in Texas alone, according to AWEA.

UniStar Nuclear, a jointly developed enterprise between Constellation Energy and AREVA Inc., told the Nuclear Regulatory Commission (NRC) that a location adjacent to Constellation Energy’s existing Calvert Cliffs Nuclear Power Plant in Lusby, Md., has been selected as the site for UniStar Nuclear’s first combined construction and operating license (COL) application. The application, which will use the U.S. Evolutionary Power Reactor (EPR) technology, will serve as the reference document for all future UniStar Nuclear COL applications to the NRC.

TXU Corp. said in a filing with the Securities and Exchange Commission that it would take a $713 million pretax charge in the first quarter for stopping development of eight coal-fired power plants. The first-quarter charge will total $463 million after taxes, TXU said. The company expects to take a charge of about $79 million during the second quarter to cancel equipment orders. The Dallas-based company said it is exposed to up to $150 million of termination and suspension costs for other equipment purchases and construction agreements tied to the scaled-back coal program.

Twenty months after Hurricane Katrina hit the Gulf Coast causing severe damage to the electric and gas infrastructure, bankruptcy Judge Jerry Brown approved Entergy New Orleans’ plan of reorganization. Under the plan, all creditors will be fully compensated and there will be no change to its work force of approximately 400 employees. Entergy New Orleans is a wholly-owned subsidiary of Entergy Corp.

Entergy Nuclear received from the Nuclear Regulatory Commission an early site permit for a possible new nuclear unit at its Grand Gulf site in Mississippi. The commissioners on March 27 authorized the NRC’s Office of New Reactors to write and issue the permit. An early site permit certifies that the site is suitable for a new nuclear unit and resolves many safety and environmental issues related to the site. The ESP remains valid for 20 years.

The U.S. Geothermal Energy Association released a report assessing progress in worldwide geothermal development since 2005. The report, titled “Update on World Geothermal Development,” said total geothermal capacity online could increase over 55 percent, from 8,661 MW in 2000 to 13,500 MW or more in 2010.

DPL Inc. has settled its lawsuit with three former executives, who will give up $134 million in deferred compensation. The settlement ends an almost three-year legal battle between the company and the former executives, who were accused of breaching fiduciary duties. Peter Forster, former chairman; Caroline Muhlenkamp, former group vice president and interim chief financial officer; and Stephen Koziar Jr., former president and chief executive officer, have agreed to the resolution in the litigation. DPL had claimed the three executives schemed to improperly withdraw more than $33 million from deferred compensation plans. DPL alleged the move triggered other losses including a $10 million hit when it lost income tax deductions in addition to penalties and losses related to failing to complete timely filings with the U.S. Securities and Exchange Commission.

American Electric Poweris among 20 companies nationwide recognized in the June edition of Working Mother magazine as ranking among the “best companies for multicultural women.” AEP is the only electric utility to be named. Earlier this spring, AEP was named one of the top 30 companies for women executives by the National Association for Female Executives.

Personnel & Promotions

Entergy Corporation Senior Vice President and Chief Accounting Officer Nathan Langston will retire in August. Theodore Bunting, Jr. will succeed Langston. Bunting served as vice president and chief financial officer of both Entergy’s utility and nuclear businesses. Following the Gulf Coast 2005 storms, Bunting was also a key contributor to Entergy New Orleans’ efforts to emerge from bankruptcy.

Public Service Enterprise Group elected Richard P. Lopriore as president of PSEG Fossil. For the last eight years, he worked at Exelon Corporation, serving most recently as Exelon Nuclear’s senior vice president for mid-Atlantic operations. Lopriore will succeed Michael J. Thomson, who resigned from PSEG in February to take an executive position at a subsidiary of Sunoco, Inc.

Westar Energy, Inc. said that William Moore will succeed Chief Executive Officer James Haines. Moore will also become a member of the board. He currently is president and chief operating officer. Haines announced his retirement as CEO effective June 30.

Puget Energy and its utility subsidiary, Puget Sound Energy, announced the elections of Eric M. Markell to executive vice president and chief financial officer, Bertrand A. Valdman to executive vice president and chief operating officer and Kimberly J. Harris to executive vice president and chief resource officer.

Sierra Pacific Resources said its board of directors elected Michael W. Yackira chief executive officer, effective August 1. Walter M. Higgins, the current CEO, is retiring as of July 31. He will continue as a member of and chairman of the board of directors. Yackira will continue to serve as the company’s president, a position he has held since February 2007. The COO position which he also assumed in February will not be refilled. Yackira will also serve as CEO of the company’s two utility units, Nevada Power Company and Sierra Pacific Power Company.

Pacific Gas and Electric Co. named John T. Conway as site vice president of the Diablo Canyon Power Plant. He most recently was site vice president of the Monticello Nuclear Plant and spent 24 years at Nine Mile Point Station. Conway holds a mechanical engineering degree from the University of Rochester.

Pramac Group named Ricardo Navarro as President of the company’s America’s operations. He previously served as Corporate Sales & Marketing Executive in the company’s headquarters.

Michael McGough has been named vice president of sales and marketing for UniStar Nuclear, a joint venture between Constellation Energy and AREVA to build new nuclear plants in the U.S.

Ershel Redd has been named president and CEO of El Paso Electric, succeeding Gary Hedrick.

William Moore has succeeded James Haines as CEO of Westar Energy. Haines retired at the end of June.

Mark Jacobshas assumed the role of president and CEO of Reliant Energy and Brian Landrum is COO. Joel Staff has retired as president and remains non-executive chairman of the board.

Public Service Enterprise Group elected William Levis as president and chief operating officer of PSEG Power, its wholesale energy business, effective June 20. He will succeed Frank Cassidy, who is retiring as head of the subsidiary, which includes PSEG Nuclear, PSEG Fossil and PSEG Energy Resources & Trade. Levis will continue as chief nuclear officer and president of PSEG Nuclear. As a result of Levis’ impending move, PSEG announced four other related executive changes: Thomas Joyce, vice president-Salem, will become senior vice president- operations for Salem/Hope Creek. Robert C. Braun, vice president-operations support, will succeed Joyce as vice president-Salem. Carl Fricker, Salem plant manager, will become vice president-operations support. George Gellrich, plant support manager-Salem/Hope Creek, will replace Fricker as Salem plant manager.

Jim Ferland, who most recently served as vice president of Global Nuclear Field Services for Westinghouse Electric Co., will serve as PNM Resources’ senior vice president of Energy Resources. Ferland replaces Hugh Smith, who will help lead the growth of EnergyCo, the company’s energy joint venture with a subsidiary of Cascade Investment, L.L.C.

Constellation Energy said that E. Follin Smith, currently executive vice president, chief financial officer and chief administrative officer, is stepping down to spend more time with her family. The company said that John R. Collins, currently senior vice president and chief risk officer, will succeed Smith.

To access this Article, go to:
http://www.power-eng.com/content/pe/en/articles/print/volume-111/issue-6/departments/startup/reserve-margins-tighten-in-california-and-new-england.html