A federal appeals court July 11 rejected the Bush administration’s plan to reduce emissions from power plants, ruling the Environmental Protection Agency went beyond its authority to create the Clean Air Interstate Rule. Known as CAIR, the program used a trading scheme among utilities to reduce emissions of sulfur dioxide and nitrogen oxides at power plants in 28 states.
EPA issued the rule in March 2005 with an aim to cut power plant emissions of sulfur dioxide and nitrogen oxides by about 70 percent by 2015. The U.S. Circuit Court of Appeals for the District of Columbia found the EPA used a flawed approach in developing the CAIR rule, said it could not be fixed in a piecemeal manner and ordered the regulation withdrawn.
 Industry may now be CAIR-free, but worries remain after court action. |
CAIR was to have been implemented through two basic mechanisms: a cap and trade program and installation of environmental controls on power plants, primarily flue gas desulphurization technology.
CAIR-designated states were to achieve the required emission reductions using one of two compliance options: 1) meet the state’s emission budget by requiring power plants to participate in an EPA-administered interstate cap and trade system that caps emissions in two stages or 2) meet an individual state emissions budget through measures of the state’s choosing.
CAIR was already well into its implementation phases. The rule was created in 2005. So-called State Implementation Plans (SIPs) were due in 2006. Phase I emission caps for NOX were to be in place in 2009. Phase I emission caps for SO2 were to be in place in 2010. And Phase II caps for both NOX and SO2 were to be in place in 2015.
Multiple parties objected to different parts of CAIR. They filed petitions for review with the federal court. Entergy and FPL Group contested EPA’s authority to base state NOX budgets on the number of coal- oil- and gas-fired facilities a state has compared to other states in the CAIR region. Utilities operating in Texas, Florida and Minnesota along with one municipality argued against including all or part of those states in CAIR. And the Florida Association of Electric Utilities asked for a review of EPA’s 2009 start date for Phase One of NOX restrictions.
The three-judge panel of the U.S. Appeals Court for the District of Columbia said CAIR’s method of calculating emission caps was “fundamentally flawed” and its trading provisions “unlawful.” The court said that solutions ranged from Minnesota Power’s position that CAIR be vacated with respect to Minnesota to North Carolina’s request that most of CAIR be sent back to EPA for changes. The court said it could not pick and choose portions of CAIR to preserve. It said that CAIR was designed by EPA as a single, regional program and that “all its components must stand or fall together.” The court said “We must vacate CAIR because very little will ‘survive remand in anything approaching recognizable form.’ EPA’s approach—region-wide caps with no state-specific quantitative contribution determinations or emissions requirement—is fundamentally flawed.”
William Bumpers, an attorney representing Entergy Corp., which challenged parts of CAIR, said a few electric companies flatly opposed the regulation but most generally favored it because it included cap-and-trade provisions. “The power-generating industry had already invested billions and billions of dollars in anticipation of the trading market,” Bumpers said. “They’re not happy with this development.”
Duke Energy sued EPA over CAIR, said spokeswoman Tom Williams, because of the low number of emission allowances the rule would have given Duke. “Our whole focus was not to overturn CAIR, but to make sure we got the appropriate number of allowances,” Williams said.
Ameren in 2006 entered into a comprehensive settlement with the state of Illinois over power plant emissions. At the time it said it would spend between $2.7 billion and $3.4 billion over the next 11 years to meet a range of regulations, including the CAIR rules. Ameren spokesperson Susan L. Gallagher said, “The decision has not yet been finalized by the court and the various stakeholders have 45 days to file for re-consideration. The decision was very broad in scope, and we are evaluating what our ongoing compliance options/requirements might be under both state and federal regulations in light of that decision.”
The EPA said it was reviewing the 60-page opinion. The Bush administration can appeal the decision, but environmental groups are calling for Congress and the EPA to begin working quickly on a replacement regulation. EPA Administrator Stephen Johnson was quoted by Reuters as saying he was “extremely disappointed” with the court’s decision. When asked, he did not answer whether there was time left in the Bush administration to rewrite and fix the rule.
“This is the rare case where environmental groups went to court alongside the Bush administration,” MSNBC quoted Frank O’Donnell, president of Clean Air Watch, as saying. “This is without a doubt the worst news of the year when it comes to air pollution.” –David Wagman
680 MW IGCC Plant Shelved in New York
The New York Power Authority is halting plans for a clean-coal facility at NRG Energy’s Huntley plant in western New York. NYPA officials say the electricity produced by the plant would be too expensive because of the integrated gasification combines cycle (IGCC) technology involved.
The state gave conditional approval to the $1.5 billion project in early 2007 and has been in talks with New Jersey-based NRG Energy since then to find ways to bring down costs. Those efforts did not result in enough of a cost reduction to continue with the project.
In early 2007 NRG Energy received a conditional award from NYPA to build the 680 MW IGCC at its existing Huntley plant site in Tonawanda, N.Y. The project was scheduled to go into commercial operation in 2013. NRG was also decommissioning four of the six coal-fired generating units at the Huntley station in line with a 2005 settlement to reduce emissions of sulfur dioxide (SO2) and nitrogen oxides (NOX).
The award was conditional because IGCC costs are about 20 percent more than the current market price for a new pulverized coal coal plant. NRG and NYPA planned to pursue tax credits or other federal and/or state funding sources to bridge the cost gap. —David Wagman
LADWP to Consider Asset Sale
The Los Angeles Department of Water and Power has hired two to help it investigate selling its coal-fired generating assets to meet new California greenhouse gas rules.
The state’s Air Resources Board issued a draft plan June 27 (see story at right) to implement a state assembly-mandated 30 percent reduction in carbon dioxide emissions by 2020. LADWP is further limited by a second California law barring the public agency from entering into financial commitments of five years or longer to buy baseload generation that exceeds 1,100 pounds of CO2 per megawatt-hour.
LADWP at present receives about 47 percent of its electricity from coal-fired power plants. Assets that may face divestiture include LADWP’s 45 percent share of the 1,800 MW Intermountain Power Project in Utah and its 21 percent share of the 2,250 MW Navajo plant in Arizona.
Goldman Sachs & Co. and J.P. Morgan Securities Inc. will provide assistance to LADWP.—David Wagman
Alberta to Fund CCS Projects
The Alberta provincial government plans to create a C$2 billion (US$1.99 billion) fund to advance carbon capture and storage (CCS) projects.
Funds will be allocated to encourage construction of Alberta’s first large-scale CCS projects. The province has issued a request for expressions of interest to begin identifying CCS proposals that may have the greatest potential of being built quickly and those which provide the best opportunities to significantly reduce greenhouse gas emissions.
With the potential to reduce emissions at facilities such as coal-fired electricity plants and oil sands extraction sites and up graders, the fund will support CCS projects that are expected to reduce emissions by up to five million tonnes annually.
Funds for the two initiatives will come from this year’s budget surplus, which the province expects will be larger than was first predicted due to higher-than-forecast oil and natural gas prices.
Alberta’s Climate Change Action Plan, which is intended to cut projected GHG emissions in half by 2050, is based on three areas: carbon capture and storage; energy conservation and efficiency; and increasingly green energy production.—David Wagman
California Air Board Issues Carbon Dioxide Rules
The California Air Resources Board issued its Climate Change Draft Scoping Plan in late June, part of the state’s plan to cut its greenhouse gas emissions by 30 percent by 2020. CO2 emissions are to be cut 80 percent below 1990 levels by 2050.
Development of the scoping plan is a central requirement of AB 32, the Global Warming Solutions Act of 2006, which calls on California to reduce its greenhouse gas emissions to 1990 levels by 2020. Governor Arnold Schwarzenegger signed the bill into law in September 2006. Release of the draft plan will be followed by further evaluation and economic modeling. The rules are to be in effect by 2012.
 CO2’s up, dude. California moves forward on emissions targets |
The mandated reductions come despite projected growth both in terms of energy use and in the state’s population, said Josh Margolis, a principal in CO2e. Speaking at the American Boiler Manufacturers Association summer meeting in San Diego in June, Margolis said the 2050 goal would amount to around 680 million tons of CO2. He said the rules mean that California is reshaping its economy in a “very short period of time.”
Central to the air board’s draft plan is a cap-and-trade program covering 85 percent of the state’s emissions. This program will be developed in conjunction with the Western Climate Initiative, comprised of seven states and three Canadian provinces, to create a regional carbon market.
The draft plan also proposes that utilities produce one-third of their energy from renewable sources such as wind, solar and geothermal and proposes to expand and strengthen existing energy efficiency programs and building and appliance standards.
The draft plan also calls for full implementation of the California Clean Car law to provide less polluting and more efficient cars and trucks. It also calls for development and implementation of the Low Carbon Fuel Standard, which will require oil companies to make cleaner domestically produced fuels.
Once the final draft is prepared, it will go to the air board for consideration in November. If adopted, the plan again will be analyzed over the next two years as it moves through the regulatory process.—David Wagman
EPA Floats Groundwater Rule for Carbon Storage
Under the auspices of the Safe Drinking Water Act, the U.S. Environmental Protection Agency (EPA) has begun the process to establish its first-ever geological requirements for the sequestration of carbon dioxide (CO2). The agency’s proposed rule is intended to assure that ground water is not adversely affected by the possible eventual need to permanently store underground CO2 captured from industrial facilities and fossil-fired power plants.
Although rules already exist for groundwater protection associated with injecting carbon dioxide for enhanced oil and natural gas recovery, this is the first rule pertaining to the permanent underground storage of CO2.
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“Under the Underground Injection Control program of the Safe Drinking Water Act we have extensive experience of regulating the injection of CO2, but not for long-term storage,” said Ben Grumbles, EPA assistant administrator for water. The rule establishes a new class specifically devoted to CO2 sequestration with extensive monitoring, testing, well design and operating specifications. Although promising, he said such long-term storage remains unproven. EPA hopes to issue a final rule in late 2010 or early 2011.
The rule will apply to owners and operators of wells that inject CO2 into the ground. Those wells will be at least a half mile below the surface. It will also seek to establish flexibility for state and federal regulators to set protective permit terms and conditions based on local geological circumstances. The rule’s proposals have been developed from groundwater considerations included in DOE’s pilot sequestration projects to date.
With proper site selection and management, EPA said it believes geologic sequestration can play a major role in reducing emissions of CO2 to the atmosphere while protecting underground water sources. “The proposed rule includes extensive requirements to ensure wells are appropriately located, constructed, tested and monitored,” Grumbles said. Monitoring and testing requirements will be maintained from the initial injection of CO2 to the eventual closure of the well and beyond.
“We are issuing this rule because we want to ensure there are environmental safeguards to prevent the migration of CO2 or any other substance into ground sources of drinking water,” said Grumbles. “CO2 is not toxic or radioactive, but what is being proposed is injecting large volumes of CO2 underground for long periods of time and under tremendous pressure.”
Major issues addressed by the proposed rule include assuring permanent extensive testing and monitoring to assure that CO2 does not migrate into an underground source of drinking water. “If it did it could push other naturally occurring fluids already underground—like salts—into that underground source of drinking water,” said Grumbles. “We want to make sure the CO2 doesn’t migrate and that there are no contaminants, even in trace levels, that might find their way into underground drinking water.”
He noted that the proposed rule includes remediation procedures should such events occur. One would be to order that injection stop. He said extensive monitoring throughout the entire lifetime of the project will let regulators know quickly of any sort of migration or leakage.
“Our experiences to date with geosequestration pilot projects throughout the country and around the world haven’t shown any problems. But we think we need to be proactive in providing ‘area of review’ analysis thoughout the project’s lifetime for tracking of the plume of CO2 and have remedial actions and responses.”
The agency will accept public comment on the proposed rules for 120 days after the proposal is published.—Steve Blankinship
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NRC Staff Approves Entergy Nuclear Spinoff
The Nuclear Regulatory Commission staff has approved the transfer of operating licenses for the FitzPatrick, Indian Point Units 2 and 3, Palisades, Pilgrim and Vermont Yankee nuclear power plants from Entergy Corp. to Enexus Energy Corp. The transfer also covers the licenses for the permanently shut down Indian Point Unit 1 and the independent spent fuel storage installation at Big Rock Point. The staff’s approval became effective July 28.
Entergy Nuclear Operations submitted an application on July 30, 2007, requesting approval of the license transfers. An Entergy Corp. restructuring will create a new independent corporation, Enexus Energy, which will own the individual licenses via holding companies. Entergy and Enexus will jointly own the company operating the facilities, Entergy Nuclear Operations, which will become EquaGen Nuclear LLC.
The agency rejected critics’ contentions that the new firm will be saddled with too much debt to ensure its ability to pay for any needed fixes at the plants or for their eventual decommissioning.
It found that a “support agreement” in which Entergy will put up $700 million toward operation and maintenance costs for the plants, plus a $1 billion line of credit backed by New Orleans-based Entergy, would be sufficient to allay those concerns.
The NRC said it looked at the projected finances of the five nuclear stations for the next five years and found that in all cases but one—Vermont Yankee’s—the plants’ revenues would exceed their expenses.
Entergy has estimated the new company will have a market value approaching $20 billion. The spin off doesn’t include Entergy’s nuclear plants in regulated markets. —David Wagman
Small-scale Nuclear Power Under Development
A team at the Department of Energy’s Oak Ridge National Laboratory (ORNL) is developing nuclear reactors that are cost-effective and a better-fit for developing nations. Widely known as grid-appropriate reactors, these nuclear reactors are smaller in size, generating typically between 250 MW and 500 MW of electricity, making them far more affordable and practical for nations that cannot accommodate current light-water reactors that can generate up to 1,600 MW of electricity. This is in part because these nations have smaller power grids and less well-developed technical infrastructures.
“These reactors hold the promise of economic development by introducing a clean and affordable source of electricity to a developing nation. These reactors are also projected to have construction times just over half the time that is required to build a large nuclear power plant,” said ORNL’s Dan Ingersoll, Global Nuclear Energy Partnership (GNEP) project director for grid-appropriate reactors.
With a staggered build strategy, two or more reactors can be built in a series, which minimizes up-front capital costs and can potentially result in quicker return on investment. Many nations have entered the nuclear age using reactors of this size range, and GNEP has identified grid-appropriate reactors as a keystone in the global expansion of nuclear energy.
“The ultimate goal is energy security for parts of the world that are facing the rapid rise in electricity demands,” Ingersoll said. “Next-generation, appropriately-sized reactors will be safer, simpler to operate, highly secure and will reduce proliferation risk.”
Issues of grid capacity, financing, project risk and other factors limit the majority of the targeted countries to consider only nuclear power plants with less than 700 MW capacity. For economic reasons, including economies of scale, only large plant designs are commercially available from traditional vendors. That will change if the grid-appropriate reactors campaign is successful.
In 2008, members of the grid-appropriate reactor team will develop a solicitation for a public-private partnership to select a U.S.-based light-water reactor design for safety and licensing support beginning in fiscal year 2009. This campaign aims to speed the development, demonstration and deployment of grid-appropriate reactors, with the first reactor ready for construction in as early as 2016.
Domestically, this effort could lead to specialized uses for nuclear reactors such as an independent power source for military bases, biofuel production, coal-to-liquid conversion and economical oil shale and tar sand recovery. Utilities in many parts of the nation may also look to smaller reactors to supplement their power generation needs as demand for energy rises.—David Wagman
Firm Believes CAIR’s Demise Could End SO2/NOX Trading
ICF International, a consulting firm, said it believes that a July 11 decision by the D.C. Circuit Court of Appeals ruling overturning the Environmental Protection Agency’s Clean Air Interstate Rule (CAIR) will have significant and wide-reaching ramifications that are only now starting to be fully digested by regulators and the industry.
Perhaps the most significant affect is the court’s finding that the Clean Air Act attainment provisions require reducing individual state contributions, as opposed to relying on national or regional reductions. Since the specific location of reductions under a cap-and-trade program is indeterminate, the court found that CAIR’s cap and trade program cannot be used to meet the state attainment requirements. ICF said that one interpretation of the ruling is that it ends cap-and-trade for SO2 and NOX as a means to address National Ambient Air Quality Standards (NAAQS).
If not pre-empted by new federal legislation—a move that might take several years to pass and promulgate—a prohibition on cap-and-trade to meet NAAQS will have several striking implications, the firm said.
First, it would “effectively eviscerate the Title IV SO2 trading program.” That program would become non-binding due to the large (7 million ton) allowance bank and the large number of scrubbers already installed or about to be installed on coal plants in anticipation of the CAIR program. Even if a large number of these scrubbers are not operated, the cap plus the bank would make Title IV allowances virtually worthless, the firm said. This, in turn, would have the effect of wiping out the allowance bank’s value, which ICF estimates is worth $7 billion.
Second, the firm said that to replace CAIR may require installing even more control systems to meet “plant-by-plant” limits. The firm said this would in effect be a return to a “command and control” approach. Plant or unit-specific limits for SO2 (and to a lesser degree NOX) could result in “significant retirements of existing coal plants in a very short time-frame.” This could exacerbate the capacity shortages that ICF said it is projecting for many regions. Pending CO2 regulations further complicate plant retrofit vs. retire decisions, the firm said.
Third, near-term emissions could rise should plants that have already scrubbed (or that had planned to scrub) delay their decisions to install or operate their controls due to low allowance prices. The firm said, however, that those scrubber investments will likely turn out to be sound decisions over the long term. On the other hand, owners of generation that planned to buy allowances to comply with CAIR could, under a plant-by-plant standard, have to choose to either install pollution control equipment or shut down.
A fourth implication of the court’s decision, the firm said, is that the NAAQS still need to be achieved, either through new regulations or legislation.
“There is an urgency to clarify the SO2 and NOX regulatory path forward both because of the implications for generation capacity and reliability, and because of the substantial increases that ICF expects in SO2 and NOX emissions, particularly in 2008 and 2009, as the industry waits for clarity.” Under existing rules, power companies will have little incentive to cut SO2 and NOX emissions beyond currently mandated levels. For example, the firm said that at the current deflated SO2 prices, it already is cheaper to buy or consume allowances than to run a scrubber.
“The actual impact this will have will largely depend upon the conditions governing the installation and operation of these controls at the individual plants—not because of the economics of a cap and trade system,” ICF said.—Steve Blankinship
Business Briefs
Progress Energy Florida said the Florida Public Service Commission approved its plans to build two advanced nuclear power plant units. The unanimous vote does not represent a decision to build the nuclear plant. Progress said it expects to make that decision by early next year. Progress must now file for cost recovery with the Florida PSC and a combined construction and operating license application (COLA) with the U.S. Nuclear Regulatory Commission, both expected later this summer. If plans are approved by state and federal regulators, the two new advanced-technology reactors could begin operating in 2016 and 2017, respectively. The company estimates the total cost of the project to be approximately $14 billion for the two units and an additional $3 billion for the necessary transmission equipment.
AmerenUE submitted a combined construction and operating license application (COLA) to the U.S. Nuclear Regulatory Commission for a potential new 1,600 MW pressurized water reactor adjacent to AmerenUE’s existing single-reactor, 1,190 MW Callaway Plant. The regulatory process for a COLA is estimated by the NRC to require up to 42 months for completion.
SunPower Corp. was selected by Florida Power & Light Co. to build a 25 MW power plant in DeSoto County, Fla. and a 10 MW project at the Kennedy Space Center. SunPower said it will design and build the facilities. The DeSoto plant is scheduled to be completed in 2009. The Kennedy Space Center project is slated to be completed in 2010.
Nebraska Public Power District will work with private developers on what could be more than $1 billion in wind projects across the state that could have a generating capacity of 400 MW. NPPD would build transmission lines and contract for much of the electricity. NPPD currently gets almost 60 percent of its electricity from coal plants and 1 percent from wind. NPPD’s goal is to generate 20 percent of its electricity from renewable energy resources by 2020.
The Public Utility Commission of Texas approved Southwestern Electric Power Co.’s proposal for a 600 MW, $1.52 billion coal-fired power plant in Southwest Arkansas. SWEPCO, a unit of American Electric Power, received approval for the plant—which could cost $2,533/kW to build—from the Arkansas Public Service Commission in November. The company also had to submit applications to regulators in Texas and Louisiana. An application by SWEPCO for an air permit from the Arkansas Department of Environmental Quality is still pending.
AES Corp. increased its China-based wind power operations through two new agreements with one of China’s largest wind power developers. AES acquired 49 percent of Guohua Energy Investment Co. Limited’s Hulunbeier wind farm, which began commercial operation in September last year in Inner Mongolia, China. The wind farm currently produces 49.5 MW of wind power. AES reached a separate agreement with Guohua to proceed with construction of Phase II of the jointly owned Huanghua wind project in Hebei Province
Rolls-Royce is establishing a new business unit to address the global market for civil nuclear power. The company estimates the worldwide market could be worth $100 billion a year in 15 years. Rolls-Royce currently claims one of the largest nuclear skills base of any U.K.-based company, with around 2,000 nuclear-focused employees in the UK, France and the U.S.
Sunflower Electric Power Corp. said it will take its fight to build two new 700 MW supercritical coal-fired units at its Holcomb plant to the Kansas Supreme Court. Sunflower said it hopes the court will overturn a state Health & Environment department rejection its project last year. The agency cited carbon emissions the new units would produce as the reason for blocking the project. Attempts to overrule the decision were vetoed by Gov. Kathleen Sebelius. The Kansas department said the state would continue to defend its decision.
Southern California Edison (SCE) has begun installing solar panels at the first of about 150 Southern California commercial rooftops that eventually will make up the utility’s two-square-mile solar generation project, which will be the largest solar panel installation in the world. SCE will attach 33,000 solar panels to a 600,000-square-foot commercial roof in Fontana, Calif., leased from ProLogis. When completed, this installation will be able to produce 2 MW of power.
Peabody Energy, ConocoPhillips and E.ON U.S. are working with the Kentucky Geological Survey to test the feasibility of storing carbon dioxide underground. The Western Kentucky Carbon Storage Foundation is investing $7.8 million to drill a test well for the sequestration test. The state is providing about $1.4 million and the energy companies will provide the remainder.
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Projects & Contracts
Acorn Energy Inc. and its CoaLogix unit secured two contracts for catalyst regeneration totaling over $5 million for delivery in 2008 and 2009. The new contracts come from one southern utility company and one mid-Atlantic utility company. CoaLogix’s current backlog in regeneration contracts represents about three times its entire 2007 revenue.
TransCanada Corp. said that its Kibby Wind Power Project won approval from Maine’s Land Use Regulation Commission, allowing it to develop a 132 MW wind project. The project will involve installing 44 3 MW Vestas wind turbine generators. The project’s capital cost is around US$320 million ($2,424/kW). Pending all remaining approvals, TransCanada said it expects to begin construction later this summer and commission the project in 2009 to 2010.
Emerson Process Management was selected by NTPC Ltd. to modernize controls at the Tanda Thermal Power Station, a 4 x 110 MW plant in India. NTPC is the largest power utility in India and the sixth-largest thermal power generator in the world. Emerson is installing its Ovation expert control system at all four units as part of a comprehensive renovation and maintenance project. At all four Tanda units, the system will monitor and control burner management and furnace safeguard supervisory systems. The system will manage 10,000 I/O points.
Consulting firm MWH has been awarded a contract by Areva NC to provide environmental services to assist in the licensing of Areva’s proposed $2 billion uranium enrichment plant in Idaho. Under terms of the $1.7 million contract, MWH will provide services for the environmental report that will be part of the license application for submission to the U.S. Nuclear Regulatory Commission. The new plant will provide uranium enrichment services to U.S. nuclear plant operators using centrifuge technology developed by the Urenco and Enrichment Technology Company Ltd (ETC), an Areva subsidiary. Its capacity will be 3 million separative work units per year.
Under a $150 million contract, GE Energy will supply a Frame 9E gas turbine, a SC5 steam turbine, a fuel gas compressor, generators and additional equipment for a 169 MW power plant at the Baoshan Iron & Steel Co. (Baosteel) complex in Baoshan District, Shanghai, China. GE previously provided similar equipment for the original power plant that was recently constructed at the site. In addition to the traditional use of natural gas, the power plant will be able to utilize waste gas created during the steel production process. The GE Energy machine can accommodate a range of fuels such as natural gas, light and heavy distillate oil, naphtha, crude oil, residual oil, steel mill gases including COREX and syngases. More than 400 Frame 9E gas turbines have been selected for power generation and industrial projects worldwide. Shipments of the GE gas and steam turbines to the site are scheduled for September and November 2009, respectively. Commercial startup of the plant expansion is scheduled for January 2010.
Advanced Metallurgical Group NV (AMG) announced that Furnaces Nuclear Applications Grenoble SA, in which its Engineering Systems Division holds a 50 percent stake, has been awarded a contract by Shaw Areva MOX Services. The contract is for the detailed engineering of two vacuum-type sintering furnaces for the mixed-oxide (MOX) fuel fabrication plant being built at Savannah River near Aiken, S.C. The second phase of the contract, expected to be awarded within one year, will involve the production, testing and delivery of the sintering systems. AMG expects the total value of the two contracts to be over $30 million. Shaw Areva MOX Services is a joint venture between construction group Shaw and Areva. The Savannah River plant design is to be based on Areva’s reprocessing plant at La Hague and its Melox MOX fabrication plant. Similar facilities based on Areva designs are nearing completion at Rokkasho in Japan.
People & Personnel
ABB named Joseph Hogan as its chief executive after months of searching to replace Fred Kindle, who stepped down in February. ABB, a leading supplier of power and automation technologies, said that Hogan, 51, would join the company on September 1. Hogan is currently CEO of GE Healthcare, a medical diagnostic technology and biosciences company, and is a member of the General Electric Co. Senior Executive Council.
John Krenicki was named a vice chairman of GE and will lead a newly created GE Energy Infrastructure business setment. He has been president and CEO of GE Energy. Previously, he was president and CEO of GE Plastics and GE Advanced Materials. Krenicki earned a bachelor’s degree in mechanical engineering from the University of Connecticut and a master’s degree in management from Purdue University.
Jeff Reinhart was named vice president at Omaha Public Power District’s Fort Calhoun Nuclear Station. Reinhart has nearly 30 years of nuclear power plant experience. He comes from the Institute of Nuclear Power Operations, where he served in a variety of management positions during a 22-year career.
Bob Randall, previously COO, has been named president and CEO of Doosan Hydro Technology. The company said he has helped guide the recent development and growth of Doosan Hydro Technology as a global provider of membrane technology solutions.
Mergers & Acquisitions
LS Power Equity Partners (LS Power) and Global Infrastructure Partners (GIP) offered to buy TransAlta Corp. for C$39 a share (US$38.8) in an all-cash transaction. LS Power currently holds approximately 9 percent of TransAlta’s common stock. TransAlta is organized into two separate business segments: generation and energy marketing. The company owns and operates 50 power plants in Canada, the United States, Mexico and Australia with 8,788 MW of capacity (not including plants in development). It also owns three surface coal mines: Highvale & Whitewood (in Alberta, Canada) and Centralia (in Washington State). The company’s fuel mix is 58 percent coal, 29 percent natural gas, 9 percent hydroelectric and 4 percent renewables. LS Power owns and operates power generation assets throughout the United States. LS Power has developed gas-fired and coal-fired facilities in various jurisdictions. LS Power currently owns and is developing a diverse mix of power generation facilities fueled by natural gas, coal, and renewable resources, including wind and solar. GIP invests in infrastructure companies and assets worldwide. TransAlta’s Board of Directors said it reconstituted its special committee of independent directors, to consider the offer and will respond in due course, said Chairman Donna Kaufman.
A FirstEnergy Corp. business unit is paying $125 million for a 45 percent stake in the Bull Mountain Mine Operations in Montana. The utility said that compared to typical eastern coal, coal from Bull Mountain has around half the sulfur and ash content. The coal’s higher efficiency is expected to help FirstEnergy avoid derates of around 170 to 200 MW that would have resulted from continued use of PRB coal. As part of the deal, FirstEnergy and its business partner will buy 80 percent of the Bull Mountain mining operations and 100 percent of the rail operations. FirstEnergy will a 45 percent interest and a partner of the Boich Cos. of Columbus, Ohio, will own a 55 percent interest. After 18 months, the joint venture will have the option to acquire the remaining 20 percent stake in the mining operations.
BP Alternative Energy has acquired the Whiting Clean Energy facility, a 525 MW natural-gas fired combined-cycle cogeneration power plant in Whiting, Ind. The plant was acquired for $210 million ($400/kW) from NiSource Inc.
Puget Sound Energy completed the purchase of a 125 MW power plant in Washington. The utility bought the natural-gas-fired power plant in Sumas, Wash., from Sumas Cogeneration Co., a unit of National Energy Systems Co., based in Kirkland. The $30 million transaction also gives PSE part ownership in a 3.7-mile pipeline that brings natural gas to the Sumas plant from the main Canadian gas-transmission pipeline into Washington state.
EPS Corp. acquired three cogeneration power plants operating at Dean Foods Co.’s facilities in City of Industry, Calif. Terms were not disclosed. The three cogeneration plants add nearly 6 MW of cogeneration power, for a total portfolio of approximately 10 MW, at Dean Foods facilities under the ownership of EPS Corp. Purchase of these three plants includes a 10-year energy purchase agreement worth $100 million.
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