Electricity usage in the United States is projected to grow more than twice as fast as committed resources over the next 10 years, the North American Electric Reliability Corp. (NERC) said in its annual 2007 Long-Term Reliability Assessment. Unless additional resources are brought into service, some areas could fall below their target capacity margins within two or three years. In parts of western Canada, demand is projected to outpace resource growth within about two years, according to NERC.
“We are at the stage where emergency situations are becoming more frequent,” said Rick Sergel, president and CEO of NERC. “Though some improvements have been made, we are requiring our aging grid to bear more and more strain and are operating the system at or near its limits more often than ever before. As operating margins decrease, we are limiting our ability to manage unplanned events like equipment failures and extreme weather,” Sergel said.
Wind, Solar, and Nuclear Generation
Wind and solar are said to be increasingly attractive generation resources, providing benefits that include fuel mix diversification and greenhouse gas emissions reductions. “Renewable resources are an important part of North America’s energy future, but reliably integrating them into the bulk power system has its challenges,” Sergel said. Large-scale wind and solar generation resources are often remotely located and will require new transmission lines to deliver their power to population centers. Furthermore, “we must pin down how much power these renewables can consistently produce during peak demand times so that they can be factored into reliability planning,” he said.
Proposed nuclear power plants, because of their large size, will also require expanding and strengthening the grid to provide for their reliable integration.
Capacity Margins
Peak electricity demand in the United States is forecasted by NERC to grow by almost 18 percent (135,000 MW) in the next 10 years. Meanwhile, committed resources to meet demand, including demand response programs, are projected to increase by 8.5 percent (77,000 MW). Counting uncommitted resources, total resources could rise by 123,000 MW or 12.7 percent. California, the Rocky Mountain states, New England, Texas, the Southwest and the Midwest could fall below their target capacity margins within two or three years if additional supply-side and demand-side resources are not brought into service, NERC said.
Aging Workforce
About 40 percent of senior electrical engineers and shift supervisors in the electricity industry are eligible to retire in 2009, according to a Hay Group study cited by NERC. This loss of expertise, made worse by a lack of new recruits entering the field, is one of the more severe challenges facing reliability today, NERC said. Support for university R&D programs, additional outreach and continual partnership between industry and government are required to address the issue.
Natural Gas Reliance
Florida, Texas, the Northeast and Southern California continue to be “highly dependent” on natural gas as a fuel for electricity generation. This dependency could affect reliability in those regions as competition for gas supply and delivery capacity increases and as Canadian imports begin to decline. Overseas markets can provide new supply, but require LNG terminal construction and increase the grid’s exposure to global economic and political risks. While a number of steps have been taken to mitigate the reliability impacts of this high gas reliance, more action is needed.
Transmission
While several transmission projects were completed in the past year, and a number of planned projects have been accelerated, projected transmission additions still lag demand growth and new generation additions in most areas, the NERC said. Transmission miles are projected to rise by 8.8 percent (14,500 circuit miles) in the United States and 4.8 percent (2,250 circuit miles) in Canada over the next 10 years.
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NERC said this is more planned transmission than projected in last year’s assessment, but financing, pricing, cost allocation, siting and permitting new transmission lines remain difficult. “NIMBY is becoming NIMS: Not in My State. Reliability of the power grid in one state affects reliability in other states too, due to the interconnected and interdependent nature of the power grid,” said Sergel. - David Wagman
IGCC Rides a Regulatory Seesaw
A Minnesota integrated gasification combined cycle (IGCC) project that appeared wounded earlier this year following unfavorable rulings by an administrative law panel of the state public utility commission seemed on the road to recovery until nearly November when utility regulators again came close to pulling the plug on the Mesaba Energy Project, perhaps for good.
Earlier this fall state utility regulators overruled a decision of its administrative panel and, in a separate action, the Mesaba project was chosen from among 143 applicants to begin the final review process for a U.S. Department of Energy loan guarantee.
But in early November, regulators came close to derailing the Mesaba project, citing recent delays and cancellations of IGCC projects in Florida, Colorado and Arizona.
“We have a whole paradigm shift now,” commission Chairman Leroy Koppendrayer was quoted as saying at a November 1 regulatory meeting.
“We don’t ever want to foreclose on the future,” Commissioner Phyllis Reha was also quoted as saying, “but I think we’re all in agreement that what we have in front of us isn’t going to fly.”
Mesaba Energy Project would be a 603 MW IGCC power plant built on Minnesota’s Iron Range. Project developers have proposed incorporating carbon capture and sequestration (CCS), assuming that state utility regulators determine it should do so. Environmental opponents insist Mesaba should not be built unless it uses CCS immediately.
“The loan guarantee offers Minnesota consumers unparalleled protection from the risks of being early movers toward innovative, climate-friendly technologies,” said Julie Jorgensen, co-president and CEO of Excelsior Energy, which is developing Mesaba. Minnesota Governor Tim Pawlenty congratulated Excelsior on the announcement, saying that Minnesotans will get the benefit of a technology that can mitigate its greenhouse gas emissions and dramatically reduce environmental impacts while enhancing energy security with abundant, domestic resources.
Rocky Road to the Iron Range
In 2003, the Minnesota legislature passed a bill requiring Minneapolis-based Xcel Energy to enter into a long-term power purchase agreement (PPA) for 450 MW of Mesaba’s output plus at least 2 percent of its retail energy needs if the PUC determined it was in the public interest. Xcel opposed the project on the grounds that it was not needed and that gas-fired generation would better serve its needs. In April, an administrative law panel recommended the PUC find the project not in the public interest and said the project could not be labeled an “innovative energy project.”
 IGCC may yet come to Minnesota’s Iron Range, or not. |
The administrative judges said the final PPA should not be approved, primarily because of its cost to Xcel Energy and its ratepayers and the likelihood that costs would increase over time. Excelsior contended that the PPA would lock in the cost of power for the contract’s 25-year life. It said this benefits ratepayers over the unpredictable cost of natural gas-fired generation and offers greater price certainty than through utility-owned coal plants.
An analyst for the Minnesota Commerce Department found that the Mesaba project would be at least 30 percent more expensive than comparable, non-IGCC power plants. The analysis found that the proposed PPA, including transmission, would cost about $99/MWh on average, some $20/MWh more than two other options, including taking power from a new unit at the Big Stone plant in South Dakota. The analyst concluded that adding equipment to capture and sequester carbon dioxide at the plant would increase costs by about $50/MWh.
Excelsior disputed those findings, which it says are based on incomplete cost information that no other expert supported with evidence in the PUC proceeding. By contrast, Excelsior submitted a report from Fluor showing comparable costs from a supercritical pulverized coal plant and the proposed Mesaba project without carbon capture. The report showed significantly lower costs when carbon capture costs were included.
In August, the Minnesota Public Utilities Commission rejected the legislature-approved PPA, which named Xcel as Mesaba’s only customer. However, it also declared Mesaba to be an “innovative energy project,” negating the administrative law judge’s earlier opinion. The commission also indicated it would explore spreading Mesaba’s output among multiple customers.
Meanwhile, federal legislation has been introduced that could benefit Mesaba by funding construction of a carbon dioxide (CO2) pipeline in the region that could move captured carbon from Mesaba to North Dakota or Canada for enhanced oil recovery use.
“We’re now working with the PUC to see if there can be several off-takers for Mesaba,” says Jorgensen. Other utilities in the state include Great River Energy, Minnesota Power and dozens of electric cooperatives and municipal systems. Noting that Xcel recently converted two Twin Cities-area coal plants to natural gas, she said, “When those come on line they will consume as much natural gas as all the residential natural gas customers in Minneapolis and St. Paul combined. We think the commission is very sensitive to that situation. We believe that as utilities unveil these natural gas-intensive resource plans, there will be a market for the power from Mesaba.”
Capture and Sequester
Excelsior says the decision to capture and sequester (and when to do so) is up to the commission. “If they tell us to do it we will,” said Jorgensen. “But why would ratepayers start paying now? It’s the consumers’ carbon footprint and a consumers’ carbon cost, so the decision should be with the commission because they protect ratepayers. Under our proposal, the commission can order us to start CCS whenever they decide to and the consumers can start paying for it. Let us firm up our proposal, submit it to the commission and agree to update our plans when told to.”
Excelsior has also filed what Jorgensen described as a groundbreaking carbon capture and sequestration plan. “We worked with the Energy & Environmental Research Center at the University of North Dakota and the Plains Regional Partnership (one of several nationally coordinated CCS initiatives) to create a comprehensive capture and sequestration plan including a carbon transporation pipeline. The pipeline would transport captured CO2 from Mesaba to oil fields in North Dakota or Canada.”
She said it would be fairly easy to capture 30 percent of the CO2 Mesaba will produce because that amount is present in the syngas and requires no chemical shift to separate it. Existing combustion turbines can handle the higher hydrogen-laden gas the process would create. “We could also do 60 percent, which requires a chemical shift of carbon monoxide in the syngas to CO2. But not 90 (percent) right now because the technology isn’t yet there for a combustion turbine to take such a hydrogen-rich gas. GE and Siemens are working on that.”
Jorgensen also notes that FutureGen, a major showcase for IGCC technology, will be designed to help develop and refine such advanced IGCC technologies and demonstrate economic viability at higher capture levels. “I think one of the reasons we have been identified by DOE for loan guarantees is the quality of our capture and sequestration plan,” she said. “It’s the level of quality and commitment they are looking for. But the purpose of this initial funding is to move the IGCC technology itself from the R&D level to commercialization. Mesaba is a commercial project and the first commercial projects have trouble getting investment grade ratings. That’s where the loan guarantees come in. And along with the tax credits, we believe we can close the 20 percent delta between the out-of-the-box cost of IGCC and the out-of-the-box cost of supercritical pulverized coal plants.”
Jorgensen said the next step is to work with DOE to structure the loan guarantee and to work with regulators in Minnesota to structure an off-take plan. “The idea is to get this fossil energy resource into various portfolios so that if Congress eventually mandates carbon reductions, we will have something already working that can cost-effectively comply with the mandate.” - Steve Blankinship
New England Utilities “Deficient” on Renewables
State laws across New England requiring utilities to buy increasing amounts of electricity generated from renewable resources will eventually force utilities to buy renewable power from Canada, said Charles Shivery, CEO of Northeast Utilities. Shivery said that taking into account all existing renewables energy sources in New England, all that are proposed and all the renewables that appear possible to develop there, “we’re still deficient.”
Shivery made his remarks at a conference sponsored by Merrill Lynch in New York City. New England’s largest electric utility, Northeast Utilities, serves Connecticut, western Massachusetts and New Hampshire.
Shivery said estimates show that by 2015 a gap of 1,500 MW will exist between available renewable power and what state standards will require. He said that means New England will have to import renewable power from Quebec and the Canadian Maritime Provinces. He added that Canada has significant energy resources and, more importantly, is willing to build some of the energy resources that may be difficult to build in New England.
 Wind turbines in New England. Photo source NREL.. |
One source of renewable energy would be wind, largely derived from building wind turbines where winds are high, on top of mountains and off the New England coast. But developing wind generation in New England has faced substantial opposition from local residents and some environmentalists.
As one example of state mandates, Connecticut requires that electricity produced with renewable sources in the state increase annually until 2020 when it will have to reach 20 percent. The region also will begin to require reductions in carbon dioxide emissions through the Regional Greenhouse Gas Initiative, which could fuel still more demand for renewable energy.
Shivery said he believes New England might be able to develop additional renewable generation from solar and wood-based biomass sources. Wood biomass, however, faces problems in some areas where it is not considered a renewable energy source.
One possible strategy would be to build new renewable generation facilities or transmission lines that either connect with Canada or link southern with northern New England, where renewable energy projects are more likely to be built. Northeast Utilities has indicated an interest in adding transmission between New England and Canada. The company has also developed one biomass power plant in New Hampshire and has shown interest in building more.
Derek Murrow, director of policy analysis for Environment Northeast, a regional environmental advocacy and research group, said New England may not become as reliant on Canadian power as Northeast Utilities thinks. While some imports from Canada may be needed to keep up with rising renewable energy requirements, new proposed projects should be able to keep up with demand. “We are optimistic that New England will site and develop significant quantities of renewables,” he said. - Steve Blankinship
Polygen Facility Would Capture and Store CO2
GE Energy and Bechtel Overseas Power Corp. signed a project development agreement with TransCanada Corporation of Calgary to develop one of the first polygeneration facilities in the country. The facility will use petroleum coke and incorporate carbon capture and storage.
The proposed polygeneration facility, to be located in Belle Plaine, Saskatchewan, is expected to use petroleum coke as feedstock to produce hydrogen, nitrogen, steam and carbon dioxide for fertilizer production and enhanced oil recovery. It also would generate approximately 300 MW of electricity.
The facility would use GE Energy’s gasification and flexible-fuel technology to generate power and support local industrial processes. GE’s scope of supply is the gasification island and the power island equipment, which includes two GE Frame 7FB gas turbines designed to run on syngas with a high hydrogen content.
Under the agreement with TransCanada, GE and Bechtel Overseas Power Corp. completed the first preliminary engineering step and will move to the next engineering step in early 2008. If this work shows that the project is economically viable, a detailed engineering design (FEED) phase will follow. If the project receives final approvals for construction, the facility would have an in-service date targeted for 2013.
“The project plans to sequester over five million metric tons of carbon dioxide annually to increase local oil production,” said John Lavelle, General Manager of GE Energy’s gasification business. “In addition, gasification allows the project owners to use a byproduct of the refining industry for fuel, instead of natural gas.” - Steve Blankinship
EPA Reports Less Smog Over East Coast
The U.S. Environmental Protection Agency (EPA) reported that smog-forming emissions of nitrogen oxides (NOX) from power plants and industry have declined in 19 eastern states and the District of Columbia. The NOX Budget Trading Program annual report indicated that summertime NOX emissions were 7 percent lower than in 2005. Emissions were 60 percent lower than in 2000 and 74 percent below 1990 levels. Reduction in NOX - which is a precursor to ground-level ozone, or “smog” - has helped reduce ground-level ozone concentrations an average of 5 percent to 8 percent in the eastern United States in the last three years. Four of five eastern ozone non-attainment areas now meet the current standard.
The EPA report tracks summertime emission reductions from 1990 to 2006 and assesses the effect of these reductions on ozone air quality in the eastern region. The largest NOX reductions occurred in the mid-central area of the eastern United States including Illinois, Indiana, Kentucky, Ohio and West Virginia.
The NOX Budget Trading Program lets electric generating units choose the best options to reduce NOX emissions during ozone season for their facilities. Options include adding NOX emission-control technologies, replacing existing controls with more advanced technologies or optimizing existing controls. This flexibility, and an active NOX allowance market, has helped lead to an over 99 percent compliance rate with the program’s requirements, according to EPA. - Steve Blankinship
Cap-and-Trade Floated for GHG Emissions
The United States should cut its greenhouse gas (GHG) emissions by between 60 percent and 80 percent by 2050 and adopt an economy-wide, mandatory GHG reduction program. That was the conclusion of a white paper released by the House Committee on Energy and Commerce staff in October.
 Cap and trade gains steam. |
In the electric power sector, a GHG program would mirror the existing Acid Rain Program and apply to generators having a nameplate capacity of 25 MW or greater. The white paper said this threshold would cover close to 4,900 units and 99.6 percent of electric power sector emissions. An alternative plan would base cap-and-trade on potential annual CO2 emissions.
The white paper said the nation’s industrial sector might be the most difficult to regulate. Some 350,000 manufacturing facilities emit CO2 from fossil fuel combustion. “Trying to include all those sources in the cap-and-trade program would add undue administrative complexity to the program particularly since many of the sources have low emissions,” the paper said. As an alternative, it said the point of regulation and level of emissions might vary based on the “nature of the emissions” and the “activities that generate them.” For example, carbon dioxide emissions from fossil fuel combustion might be covered differently than methane emissions from coal mining, which might be covered differently than fluorinated gases emitted during production.
The report said the “appropriate thresholds and points of regulation” for the industrial sector must account for the “potential for leakage from the electricity generation sector” as well as “competitiveness concerns raised when some industrial facilities generate their own electricity.”
The white paper said a cap-and-trade-program should cover carbon dioxide (which it said amounted to 84 percent of GHG emissions in 2005), methane (7 percent), nitrous oxide (7 percent) and fluorinated gases (2 percent), which include hydrofluorocarbons (HFCs), perfluorocarbons (PFCs) and sulfur hexafluoride (SF6).
The committee is expected to introduce legislation to create such a program. - David Wagman
Canadian Nuke Would Serve Oil Sands
Only weeks after NRG Energy announced plans to file for an application to build the first new nuclear plant in the U.S. in nearly three decades, Energy Alberta has submitted a permit application to the Canadian Nuclear Safety Commission to build the first new nuclear reactor in Canada in 25 years. The twin-reactor plant would be near the town of Peace River in northern Alberta. The $6.2-billion (Canadian) Peace River nuclear plant would provide power primarily to companies developing petroleum resources in the oil sands region and would be the first Canadian reactor outside of Ontario.
Energy Alberta is partnering with Atomic Energy of Canada (AEC) on the project. AEC would supply twin CANDU reactors to generate up to 2,200 MW. Earlier, a project spokesman said that 70 percent of the proposed plant’s power output could serve one industrial customer, but has since said that multiple customers potentially exist for the plant’s energy.
The project is, however, far from a done deal. Environmental opposition exists and developers are mounting a public outreach campaign to win community support. One opposition group has brought in scientists to address concerns about safety and waste storage as well as issues over increased seismic activity due to oil-sands exploration.
Despite the fact that nuclear plants produce no greenhouse gases, opponents say that the fact that a major portion of the plant’s power would go to extracting oil from sand negates any environmental advantage. Developers point out that Alberta is “sitting on billions of barrels of oil” and the power plant will make it possible to produce that energy. - Steve Blankinship
CO2 Capture Cost
The cost to incorporate carbon capture into coal-fired power plants could be enormous. Forget about sequestering; just capturing 2.
Using today’s proven technology, the cost of capturing CO2 - whether building onto an existing power plant or into a new plant - would be onerous to say the least. Dr. James Katzer, executive director of MIT’s Laboratory for Energy & the Environment and author of the study “The Future of Coal,” which examined carbon capture and sequestration, concludes it may be cheaper to build a carbon-capture coal plant from scratch rather than try to retrofit an existing plant.
Pinning down a specific retrofit capital cost is tough, but it could easily be $800/kW based upon commercially available technologies. That’s just for starters. The power consumption penalty such retrofits would present would likely be around 30 percent. A presentation by EPRI’s Neville Holt showed that adding capture with the Fluor Econamine process to a supercritical plant would reduce net power from 600 MW to around 425 MW. Adding the process to a 750 MW unit could drop output to around 550 MW. - Steve Blankinship
Western Bituminous Coal Production Seen Increasing Over 2006 Levels
Supply and demand activity for mines that produce bituminous coal in the western United States will improve only slightly in 2007 over 2006, reports Hill & Associates in its latest comprehensive review of coal production in the region. In the seventh update of its “Western Bituminous Coal Supply Study,” Hill & Associates, a Wood Mackenzie company and coal industry forecaster, looks at historic and future production, operating costs, capacity additions and projected demand and prices for mines in the Four Corners Region, Colorado, Utah and Southern Wyoming. Projections are made for the period 2007 to 2016.
“Over the past several years, western bituminous coal production ranged from 117 million tons to 121 million tons per year,” said John Hanou, principal analyst for Hill & Associates. However, last year production dropped by 9 million tons as a result of excessive stockpiles at the nation’s utilities that reduced demand, the closure of the 4.5 million tons per year Black Mesa mine and mining problems at several longwall operations in Colorado and Utah. “We are somewhat optimistic there will be improvement in the future, albeit a slight one,” he said.
Production overview highlights of the report include the following:
- Four Corners production is mostly captive to mine-mouth power plants. The region has ample surface mineable sub-bituminous reserves at low ratios. Peabody and BHP Billiton are the largest producers. Production is currently around 33 million tons a year, with a potential for 60 million tons a year if demand materializes.
- ; Colorado has ample underground and surface bituminous coal reserves that can support efficient longwall and strip operations. Thanks to strong demand in the eastern United States for low-sulfur coal, production increased by 10 million tons from 2000 to 2004. Production is currently around 36 million tons a year with the potential for 80 million tons a year. Peabody, Rio Tinto, Arch and Oxbow are the largest producers and are in a position to retain their size status.
- Utah production has been challenged and will continue to be so due to poorer mining conditions, reserves farther away from rail transportation and the production of higher sulfur coal. Problems at several mines will cause production to drop from 26 million tons to 24 million tons in 2007. Arch, Murray Energy and PacificCorp are the largest coal producers.
- Southern Wyoming production has ranged between 13 to 17 million tons a year and is mostly captive to several power and industrial plants. The region has ample surface and underground mineable reserves of sub-bituminous and bituminous coal that can be developed. PacifiCorp, Chevron Mining and Kiewit are the major producers. Arch may become a major player if it successfully develops a coal-to-liquids plant at Medicine Bow.
Overall, shipped quality has deteriorated in the western bituminous region in recent years, productivity has remained relatively flat and, since 2004, nearly all mines saw an increase in production costs, estimated at around 25 percent from 2004 to 2006. Spot market prices also dropped “precipitously” in the second half of 2006 and the first half of 2007 and Hill &Associates said it believes the marginal prices for western bituminous coal will continue to decline slightly until 2011, then increase.
In spite of some challenges, western bituminous coal demand is expected to increase from 112 million tons in 2007 to 128 million tons in 2016, said Hanou. “Proposed new plants in the region could certainly buoy the demand and several projects that would burn local coal have been announced in the niche market area. If any of these come to fruition, they would boost the demand substantially.” - Teresa Hansen
Construction & Contracts
Tennessee Valley Authority (TVA) has chosen Bechtel Power Corp. to lead the engineering, procurement and construction to complete Unit 2 at Watts Bar Nuclear Plant in Spring City, Tenn. When completed in 2012, Watts Bar Unit 2 will add approximately 1,200 MW. Work on the original plant was stopped in 1985 when it was about two-thirds complete. The five-year, $2.5 billion project will bring the plant up to current engineering and safety standards. Bechtel previously supplied engineering, start-up and other technical services to the $1.8 billion restart of TVA’s Browns Ferry Unit 1. Bechtel also worked for TVA on the restart of Browns Ferry Units 2 and 3 in the 1990s and performed steam generator replacements on Unit 1 at TVA’s Sequoyah Nuclear Plant and Watts Bar Unit 1.
GE Energy received a contract worth more than $350 million to supply 167 of its 1.5 MW wind turbines to Third Planet Windpower for farms in Texas, New Mexico, Nebraska and Wyoming. These farms will be ready for turbines in 2009.
Babcock Power Environmental Inc. was awarded a contract to design and supply two wet flue gas desulfurization systems for Basin Electric Power Cooperative. The systems will be installed at Basin Electric’s 660 MW, lignite-fired Leland Olds Station near Stanton, N.D. The contract includes the design and supply of two WFGDs complete with absorber island, limestone preparation and gypsum dewatering systems. The contract has an approximate value of $70 million and is scheduled for completion in 2010.
Under agreements totaling more than $750 million, GE Energy will supply six Frame 9FB gas turbine-generators and associated services to EdF for the utility’s electrical power production facilities in France and elsewhere in Europe. The new machines will be featured in combined-cycle power plants. In addition to supplying the gas turbines, the scope of the agreements with GE include contractual services, maintenance services and spare parts for 12 years.
Horizon Wind Energy signed a contract for 400 MW of wind turbine capacity with Suzlon Wind Energy Corp. The contract calls for delivering 200 MW of turbine capacity in 2008 and another 200 MW of capacity in 2009. The agreement includes the supply of 95 Suzlon S88-2.1 MW wind turbines in 2008. Another 95 Suzlon S88-2.1 MW units will be provided in 2009.
Vogt Power International Inc. was selected by Southern Power to supply the heat recovery steam generator (HRSG) and associated equipment for the Orlando Utilities Commission, Curtis H. Stanton Energy Center, Orlando, Fla. Vogt Power will design, engineer, manufacture and deliver one duct-fired, three pressure-level, natural-circulation HRSG to be installed behind a modified GE Frame 7FA gas turbine. The HRSG will be equipped with a multi-pollutant control system including an SCR system for NOX removal and CO catalyst for carbon monoxide reduction.
OG&E Electric Services, Public Service Company of Oklahoma and the Oklahoma Municipal Power Authority agreed to end agreements to build and operate the 950 MW Red Rock generating unit. The announcement followed an Oklahoma Corporation Commission order verifying its September decision to deny construction pre-approval. OG&E estimated its share of costs in the aborted power plant’s planning phase to be between $18 million and $20 million, which the company intends to recover through the regulatory process.
The U.S. Environmental Protection Agency (EPA) approved a permit to add a new unit to the coal-fired Bonanza electric plant on Ute tribal land in Utah. The permit is among the first decisions of its type for the EPA since a Supreme Court ruling last winter that said the agency had authority to limit carbon dioxide. In approving the Bonanza application, EPA required no curbs on carbon dioxide. The existing Bonanza plant generates about 400 MW of electricity. The new unit would turn waste coal into an additional 86 MW. Deseret Power Electric Cooperative owns the plant.
Washington Group International won a contract from Public Service of New Hampshire to provide engineering, procurement support and construction management services for a flue gas desulfurization system installation that will service the two fossil-fuel-fired units of the utility’s 478 MW Merrimack Station. The scrubber system will work with an existing selective catalytic reduction system. When the project is complete, the plant will comply with New Hampshire’s new mercury emissions limitations as well as the federal Clean Air Mercury Rule.
Business Briefs
The proposed nuclear-waste storage facility at Yucca Mountain in Nevada will need up to three times its current funding or the program’s 2017 opening date will have to be delayed. Edward F. Sproat III, director of the Department of Energy’s Office of Civilian Radioactive Waste Management, said that beginning next year a doubling or tripling of annual project funding would be needed. He made the remarks in congressional testimony. The cost of building and operating the nuclear waste site through 2119 was estimated in 2001 at $57.5 billion, including costs incurred since the project began in 1983. A revised estimate, expected by the end of 2007, will include the cost of accepting about 30 percent more spent nuclear fuel through the repository’s closing in 2133.
American Electric Power (AEP) reached a settlement agreement with the U.S. Environmental Protection Agency, eight states and 14 environmental organizations, ending almost eight years of litigation regarding alleged violations of the New Source Review provisions of the Clean Air Act. AEP admitted no violations of law and all claims against AEP were released. However, under terms of the settlement agreement filed in the U.S. District Court for the Southern District of Ohio, AEP agreed to annual sulfur dioxide and nitrogen oxide emissions limits for 16 coal-fueled power plants in Indiana, Kentucky, Ohio, Virginia and West Virginia. The company also agreed to install additional emissions control equipment on two plants. AEP also will provide $36 million for environmental projects coordinated with the federal government and $24 million to the states that were parties to the agreement for environmental mitigation. AEP will pay a civil penalty of $15 million.
Clipper Windpower is to develop a new generation of offshore wind turbines in northeastern England. Regional development agency One North East has agreed to invest $10.2 million to support Clipper’s “Project Britannia,” a plan to develop a 7.5 MW offshore wind turbine. Clipper Windpower is to use facilities at the New and Renewable Energy Centre in Blyth, Northumberland, UK, to construct the prototype offshore turbine, known as “Million Barrel Equivalent.”
The Department of Energy will guarantee loans for up to 80 percent of the total construction cost of new nuclear power plant reactors. Because of budget constraints, however, the earliest any company proposing to build a new nuclear power reactor could benefit is 2009. Previously, DOE would have guaranteed loans for only about two thirds of total construction costs of new nuclear reactors and other projects.
EPA plans to develop regulations to establish a clear path for geologic sequestration of carbon dioxide. Once completed, the regulations are expected to ensure a “consistent and effective permit system” under the Safe Drinking Water Act for commercial-scale geologic sequestration programs. EPA plans to propose regulatory changes next summer.
Xcel Energy Inc.’s Northern States Power Co. unit won a lawsuit against the federal government involving nuclear waste disposal from the utility’s Minnesota nuclear plants. Xcel filed the lawsuit nearly a decade ago over disposal of spent nuclear fuel from the Prairie Island and Monticello plants. The damage award includes around $43.1 million for construction and operation of on-site storage facilities, $48.7 million for compliance with legislative mandates and $24.7 million to cover expenses.
Tennessee Valley Authority (TVA) is seeking a license from the Nuclear Regulatory Commission to build a new two-reactor nuclear power plant at TVA’s Bellefonte site on the Tennessee River in northeast Alabama. TVA is applying for the license as a partner in the NuStart Energy Development LLC consortium. The TVA board voted earlier this year to seek an NRC license to build a nuclear power plant.
EPA recently listed Units 1 and 2 at AmerenEnergy Generating’s Newton Power Station as the second and third lowest emitters of nitrogen oxide among all U.S. coal fired plants operating without selective catalytic reduction NOX removal equipment. In January 2007, Newton personnel with technical support from equipment supplier Alstom began a NOX reduction program that uses process tuning, which involves making adjustments to boiler operating levels.
FPL Group Inc. announced a $2.4 billion investment program aimed at increasing U.S. solar thermal energy output. The planned investment includes up to $1.5 billion in new solar thermal generating facilities in Florida and California over the next seven years, starting with a project involving Florida Power & Light (FPL). It also includes up to $500 million by FPL to create a smart network that will provide its customers with enhanced energy management capabilities. The planned investments are in addition to the company’s intention to spend $20 billion in new wind generation.
Hitachi Ltd. will invest the equivalent of $265 million by around 2010 to boost capacity at its nuclear power equipment factory in Japan. Hitachi’s factory in Ibaraki prefecture near Tokyo makes main structures that are located inside nuclear reactors. Hitachi plans to build an additional plant there for items such as carbon-based parts and introduce a production line by 2010 for welding large structures. Hitachi began bolstering the plant’s capacity last year, preparing for an expected rush of nuclear power plant demand after 2010.
NRG Energy Inc. told the California Energy Commission it wants to modernize the Encina Power Station in Carlsbad, Calif., the first phase of a plan to replace the existing plant with a cleaner and more efficient facility to be located adjacent to the current power plant. The project, known as the Carlsbad Energy Center, will include retiring three older generating units while increasing the facility’s net output by 200 MW.
Tampa Electric said it no longer plans to meet its 2013 need for baseload generation through the use of integrated gasification combined-cycle technology, IGCC. Primary drivers behind the decision include continued uncertainty related to carbon dioxide regulations, particularly capture and sequestration issues and the potential for related project cost increases. Because of the economic risk of these factors to customers and investors, the company said it believes it should not proceed with an IGCC project at this time.
Fort Defiance Indian Hospital deployed two Active Power CleanSource uninterruptible power supply (UPS) systems to protect critical equipment at its northern Arizona facilities. Active Power provided turnkey services to install and commission the 600 kVA CleanSource and 300 kVA Expandable CleanSource systems.
SUEZ Energy North America established a new division focused on renewable energy development following completion of its acquisition of the Canadian wind power development company Ventus Energy. Ventus has a portfolio of 25 wind energy projects in six provinces in eastern Canada. The portfolio includes close to 2,000 MW of electricity generation in various stages of development. SUEZ said it would leverage the wind development expertise to increase its market presence in Canada and expand into the United States.
Nordic Windpower Ltd., which makes two-bladed, utility-scale wind turbines, said that Goldman Sachs has invested in the company. The new money will enable Nordic to fill orders for wind turbines at a time when the industry faces persistent supply constraints. The investment will let Nordic deliver its turbines as early as 2008.
Portland General Electric (PGE) said its Biglow Canyon Wind Farm has begun generating electricity. Phase one is on track for completion by the end of this year. It will comprise 76 turbines with an installed capacity of 125 MW. When all three project phases are completed, PGE expects the wind farm to have between 400 and 450 MW of installed capacity. The Biglow Canyon project was developed by Orion Energy LLC and will be built, owned and operated by PGE.
A research partnership between Ottawa, Alberta and Epcor Utilities is expected to lead to a full-scale coal gasification power plant. The project will be located at EPCOR’s Genesee Generating Station west of Edmonton. The engineering design project is expected to cost $33 million, an expense to be split equally among the Canadian government, EPCOR and the Alberta Energy Research Institute. Over the next two years, researchers will conduct front-end design work for a power plant that would turn sub-bituminous coal into synthesis gas and hydrogen. Work is scheduled for completion in 2009, and a 500-MW generating station could be in operation in Alberta as early as 2015.
Wyoming state environmental regulators issued an emissions permit for the Dry Fork Station coal-fired power plant. Basin Electric Power Cooperative officials said construction of the $1.3 billion, 385 MW plant began once the state gave its approval. The issuance also prompted Basin Electric to withdraw its application for a $750 million federal loan. The plant is slated to be operational by 2011.
A preliminary report to the Wisconsin Governor’s Task Force on Global Warming calls for removing a state roadblock to nuclear power plant construction. Initial recommendations include a call to drop a requirement, passed by the Wisconsin Legislature more than 20 years ago, that no new nuclear plants can be built until a permanent site is established to store their radioactive waste. A second condition requiring that any new nuclear plant be economically advantageous for Wisconsin ratepayer would remain in place.
Xcel Energy Inc. is delaying plans for a 600 MW IGCC power plant in Colorado because of cost concerns and a desire to find project partners. Xcel may not propose the plant to Colorado regulators until 2009 or later. Xcel also pushed back the planned completion date to 2016.
Mergers & Acquisitions
Australian investment firm Babcock & Brown Ltd. bought offshore wind power developer Bluewater, which is seeking to build a wind farm off the Delaware coast. Terms were not disclosed. The companies said Bluewater would continue to negotiate a power purchase agreement with Pepco Holdings Inc.’s Delmarva Power subsidiary. The proposed 150 turbine, 450 MW wind farm would be 11 miles offshore. Bluewater, of Hoboken, N.J., was part of Arcadia Windpower. Babcock & Brown, of Sydney, manages more than $50 billion in assets. Its portfolio includes more than 1,200 MW of wind power owned directly or though its family of funds, including 18 wind farms in eight states.
J-Power USA Generation, the joint venture company of J-Power USA Investment Co. and the John Hancock Life Insurance Co., completed its purchase of 100 percent of the equity interests of Green Country Holding, which owns the Green Country power plant.
KGen Power Corp. said it paid $35 million to end its June 18 purchase and sale agreement with affiliates of Complete Energy Holdings, which was to include 1,859 MW of capacity at the La Paloma, Calif., site and the Batesville, Miss., site. The proposed price was $1.336 billion plus working capital adjustments. KGen cited several factors, including “lengthy, unplanned outages” at the plants and “prevailing conditions in the capital markets.”
Paul Prager and Natural Gas Partners plan to buy generating and transmission assets owned by the City of Vernon, Calif., in a transaction valued at $342 million. Assets include the 134 MW Malburg Generating Station, economic interests in 11 MW generated by the Palo Verde Nuclear Generating Station and 22 MW from the Hoover Uprating Project, as well as the city’s interests in the Mead-Adelanto Transmission Project and the Mead-Phoenix Transmission Project. The deal is expected to close by the first quarter of 2008.
TXU Corp. completed its merger with Texas Energy Future Holdings Limited Partnership, led by Kohlberg Kravis Roberts & Co., Texas Pacific Group and Goldman Sachs Capital Partners. TXU shareholders approved the merger on September 7. TXU Corp. changed its name to Energy Future Holdings Corp.
National Grid will divest the Ravenswood Generating Station, which was acquired as part of the company’s August purchase of KeySpan Corp. Divestiture was a condition of the New York State Public Service Commission order approving the acquisition of KeySpan by National Grid. National Grid expects to announce the winning bidder for the Ravenswood asset by the end of the first quarter of 2008.
Puget Energy has entered into a merger agreement with a group of infrastructure investors led by Macquarie Infrastructure Partners, the Canada Pension Plan Investment Board and British Columbia Investment Management Corp. The group will buy all outstanding shares of Puget Energy for $30.00 a share in cash, representing a 25 percent premium. It also will also assume $3.2 billion of debt. The transaction has an enterprise value of $7.4 billion. The transaction is expected to close during the second half of 2008, subject to approval by Puget Energy’s shareholders and regulatory approvals, including those from the Washington Utilities and Transportation Commission and the Federal Energy Regulatory Commission. PSE estimates it will need more than 1,300 average-megawatts (aMWs) of new electricity supply by winter 2014-15. This need is expected to increase to more than 2,600 aMW by 2025 - roughly equivalent to the power demand of two cities the current size of Seattle. The company owns 2,471 MW of generating capacity. It has contracts for an additional 2,000 MW of supply.
Hong Kong-based Cheung Kong Infrastructure Holdings will buy TransAlta Power, which has a 404 MW stake in six Canadian power plants, for C$629 million (US$644m). TransAlta Power owns a 49.99 percent interest in TransAlta Cogeneration that has net interests of 815 MW in five natural gas-fired cogeneration plants in Alberta, Ontario and Saskatchewan and a coal-fired plant in Alberta. In May, TransAlta Power’s board began considering a sale because of federal tax law changes.
People & Personnel
Environment One Corp. (E/One) said George A. Earle III will replace Philip Welsh as company president. Earle served as E/One’s VP-Technology and Business Integration and previously was with Plug Power.
Jack Davis is retiring as president and COO of Pinnacle West Capital Corp. and CEO of Arizona Public Service Co. (APS). The Board of Directors named current APS President Don Brandt to fill the Chief Executive Officer position. Actions are effective March 1, 2008. With more than 20 years of experience in the industry, Brandt joined the company in 2002 as senior vice president and CFO. He was promoted to executive vice president in 2003 and president of APS in 2006.
UniStar Nuclear Energy, LLC appointed George Vanderheyden as president and chief executive officer, Kathleen Hyle as chief financial officer and Steven Miller as secretary of the company. Vanderheyden also serves as a senior vice president for Constellation Energy Nuclear Group and will be responsible for overseeing the potential development and deployment of Evolutionary Power Reactors in the United States and Canada. Hyle will be responsible for managing the financial risk associated with the potential fleet of new nuclear assets. She also serves as senior vice president of finance and chief financial officer for Constellation Energy Nuclear Group. Miller also serves as general counsel and secretary as well as senior vice president of strategy for Constellation Energy Nuclear Group.
The Electrical Generating Systems Association announced its 2008 Officers and Board of Directors, effective January 1. Warner Bauer, Kickham Boiler & Engineering Inc. Vaporphase Div., St. Louis, Mo., now serves as EGSA’s 2008 President. He was the association’s president-elect in 2007 and vice president in 2006. Greg Linton, JRS Custom Fabrication, Inc., Ocala, Fla., now serves as EGSA’s President-Elect. Ron Hartzel, Eaton Electrical, Pittsburgh, Penn., is vice president. John Kelly Jr., Kelly Generator & Equipment Inc., Upper Marlboro, Md., serves as secretary/treasurer, and Gary Kidwell, ASCO Power Technologies, Lodi, Calif., is the Association’s immediate past president.
PG&E Corp. said its board of directors elected Greg S. Pruett to senior vice president, Corporate Relations. In addition, the board of directors of PG&E Corp.’s utility unit, Pacific Gas and Electric Co., elected Patricia M. Lawicki as senior vice president and chief information officer for the utility; Geisha J. Williams as senior vice president, Energy Delivery; William D. Hayes as vice president, Maintenance and Construction; and Mark S. Johnson, vice president, Electric Operations and Engineering.
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