Turbines from GE Energy made up 43 percent of all new wind power capacity installed in the U.S. during 2008. Vestas ranked second at 13 percent, according to annual wind energy industry rankings from the American Wind Energy Association (AWEA).
Other top wind installers included Siemens and Suzlon at 9 percent each and Gamesa at 7 percent. Acciona, REPower, Fuhrlander, DeWind and AWE all entered the U.S. market in 2008.
During 2008 wind energy employment grew 70 percent to around 85,000.
NextEra Energy Resources remained atop the list of project owners, with 6,290 MW of wind power assets. That equals roughly 25 percent of the total U.S. installed capacity base. The three companies that made up the next 25 percent share are Iberdrola Renewables, MidAmerican Energy (including PacifiCorp) and Horizon-Energia de Portugal.
Iowa, with 2,791 MW installed, passed California (2,517 MW) for the No. 2 position in wind power generating capacity. The top five states in terms of capacity installed were Texas, with 7,118 MW; Iowa, with 2,791 MW; California, with 2,517 MW; Minnesota, with 1,754 MW; and Washington, with 1,447 MW.
Oregon moved into the 1,000 MW club, which now counts seven states, including Texas, Iowa, California, Minnesota, Washington and Colorado.
Indiana saw the fastest growth rate, expanding installations from zero to 131 MW (and thereby causing calculators to read “error”). Indiana’s infinite growth rate was followed by Michigan (48 percent), Utah (21 percent), New Hampshire (17 percent) and Wisconsin (6 percent).
Minnesota and Iowa now receive over 7 percent of their electricity needs from wind. Minnesota ranked first in this list in 2008 (7.48 percent), followed by Iowa (7.1 percent). The rest of the top five are Colorado, North Dakota and New Mexico.
Ten new manufacturing facilities came online, 17 expanded and 30 were announced in 2008. Investments span 24 states: Arkansas, Colorado, Iowa, Michigan, Nebraska, New York, Tennessee, Wisconsin, South Carolina, North Carolina, North Dakota, Oklahoma, Illinois, Alabama, Ohio, Indiana, Montana, Texas, Minnesota, Idaho, South Dakota, Pennsylvania, Oregon and Massachusetts.
Approximately 85,000 people worked in the wind industry at the end of 2008a 70 percent increase from 50,000 a year earlier. They held jobs in areas as varied as turbine component manufacturing, construction and installation of wind turbines, wind turbine operations and maintenance, legal and marketing services.
The country’s wind power generating fleet had about 25,300 MW in place as of the end of 2008.Jeff Postelwait
EPRI Lays Out an Electric Vehicle Future
Electric vehicles (EVs) in the form of plug-in hybrid gasoline/electric cars will likely be a part of our not-so-distant future. And it will be the job of electric utilities to establish a residential infrastructure to fully integrate them into the grid.
At a joint news conference held by General Motors, the City of San Francisco and the Electric Power Research Institute (EPRI) in April, Mark Duval, who heads EPRI’s electric car initiative, discussed key issues that must be addressed to fully integrate a significant number of EVs into the nation’s power grid.
Utilities have an obligation to provide all customers with guaranteed service at the best cost and since the 1970s, EPRI has conducted research on behalf of the power industry on electric vehicles’ potential as an alternative to petroleum.
The goal of 1 million electric vehicles would mean less than a 1 percent hike in delivered energy.
“We can’t build cars,” said Duval. “Our job is to provide electricity to every person in the country. We follow the technologies, advise electric utilities on their readiness and do what we can to assure the right technologies reach the market.”
He said the electric grid’s ability to handle the load of a significant number of plug-in hybrids is hardly an issue. There is no practical limit to how many vehicles the grid can handle.
Noting that utilities are good at managing very large capital intensive systems, he said managing a vehicle charging infrastructure will not be nearly as complicated as operating a grid over thousands of miles and millions of customers. But it still represents a big, complex task.
“We want to work with the auto industry toward having electric vehicles and a smart grid that are truly integrated,” he said. “Utilities can serve the load without much problem. But we want to get there as soon as possible.”
True integration won’t come with the first generation of plug-in hybrids, but it certainly will with the second generation already being developed by General Motors and other vehicle manufacturers. True integration into the grid means having a smart grid and EVs “talking” to each other and exchanging relevant information. It means letting customers access the greenest electricity or the lowest cost electricity, convenient charging, and convenient billing. That will create maximum value for all utility rate payers and electric vehicle owners.
In addition to making large investments in smart grid technology, utilities are also investing in new low carbon generation, currently centered on renewables, but also related to advanced fossil combustion technologies and nuclear. New capacity being added today is dominated by two sources: combined cycle natural gas plants and renewables, largely made up of wind resources. These low-or no-carbon-emitting sources will help power added load from EVs and also lower greenhouse gas emissions.
According to EPRI projections based on forecasted electrical consumption in 2010, adding 1 million electric vehicles driven by commuters who use their car batteries to their maximum most days would produce less than a 1 percent increase in delivered energy. “It’s unlikely electric vehicle loads would ever be anything the industry can’t handle,” said Duval.
Under an electric vehicle scenario, EVs will become another home appliance added to the household’s electric load. The typical consumption of a General Motors Volt plug-in hybrid would be about 2,500 kWh per year. That’s roughly the same as from the typical usage of three new plasma televisions over the same period.
The Volt has a range of 40 miles on electricity before switching to a gasoline-fueled electric generator to give it a driving distance comparable to today’s typical gasoline powered vehicle.
“In the long term, we see a potential 500 million tons per year reduction in carbon dioxide emissions for the auto industry, due almost entirely to replacing gasoline with lower carbon-intense electricity,” said Duval. “It would also reduce petroleum use by three to four million barrels a day.”
EPRI believes it will be essential for EV owners to have one residential charger per vehicle and the electric utility sector needs to make that process as seamless as possible. “It will be a challenge,” he said, “and is currently an uncertainty that the person buying an electric vehicle will have to deal with.”
Home charging may require some work on the residence. Some people will take their vehicles home and plug them into a 120 volt outlet. Some may want faster charging requiring a box for 240 volt charging. “There are utilities who will offer that installation as a service,” said Duval. Some are already planning to offer it as a free service as an incentive for the market.
Most charging will take as the residential level. “People will want access to low cost electricity and you will get the lowest cost at home and generally off-peak,” he said. “So this is the most important place for utilities to engage. To help their customers get the equipment installed in the homes as quickly and conveniently as possible.”
The next place charging infrastructure will occur is at the workplace and retail stores. “You can do a significant amount of charging during the day,” said Duval. “That will entail a different approach. Businesses will have several chargers, and they will want to install and manage them is a cost effective way. Utilities should be able to encourage and help these customers to do these things.”
Last will come public charging and it presents the most difficult challenge. Public charging would benefit consumers who buy an electric vehicle but have no dedicated parking space or wish to charge when away from their space. Duval said public charging will be difficult and expensive.
“We’re not sure how we’re going to handle it because it’s very expensive and complicated.”
One way it can happen is for municipalities to undertake it as a public service. Another option is for utilities to do it in the ratepayer interest as part of their rate structure and own and operate public charger infrastructure. And then there could be start-up companies that have technologies they would like to get into the public marketplace. They might want to install and operate chargers in those areas.Steve Blankinship
Reheat Recovery Boiler Aimed at Boosting Power Output
Babcock & Wilcox is looking for a pulp and paper company willing to install a reheat recovery boiler that could turn the manufacturing facility from a power consumer into a power generator. The timing for such an investment may be right. For one thing, the average age of a paper industry boiler is around 50 years. For another, the potential exists for a manufacturing facility to qualify for green energy credits. That’s because paper mill boilers use black liquor, a carbon-neutral biomass fuel derived as a part of the paper-making process.
Payback could be around five years and power output from the new boiler could be as much as 50 percent greater, topping out at around 40 MW for plants that have been evaluated.
Dual pressure reheat recovery boiler from B&W
“In the U.S. there are 115 boilers that are running at 900 psi (62 bar) or less,” says Tim Hicks, B. Eng. and pulp and paper business development manager for Babcock & Wilcox (B&W) in describing the market. The capital investment to install a heat recovery boiler would include a new boiler, precipitators, evaporator modules and turbine.
A pulp mill’s ability to generate steam is limited by the need for process steam. Unlike a utility plant, most of the steam is required for low pressure process steam. This means pulp mills typically do not have enough excess steam for feedwater heating, which would improve cycle efficiency and increase electric power generation. But increasing the feedwater temperature means higher gas temperatures leaving the economizer, reducing boiler efficiency. Recovering that heat would require a gas to air airheater.
Decades ago, engineers tried to increase recovery boiler pressures, but the reducing environment in the lower boiler caused excessive corrosion, Hicks says. In a black liquor recovery boiler, water from a tube leak can lead to a violent smelt-water reaction that can literally destroy a boiler.
For years recovery boilers were limited to pressures less than 900 psi to keep corrosion under control. The 1990s saw a move toward higher pressures in an effort to get boost power generation. These efforts were limited by metallurgy in the lower boiler.
“We weren’t getting the metallurgy to survive the reheat cycle,” Hicks says. Composite tube and weld overlays allowed pressures of 1,500 psi and correspondingly higher temperatures seemed acceptable. But in-canal overlays continued to experience burn-back and cracking issues.
Engineers decided to test a dual-pressure design. A dual pressure boiler allows the lower furnace to operate at pressures below critical corrosion temperatures. The technology allows recovery boilers to be designed without the need for alloy materials to protect the lower furnace from corrosion. Increased power generation stems from applying high pressure reheat steam cycles.
According to a B&W white paper, the lower furnace of a recovery boiler would operate at a low pressure and the upper furnace would operate a high pressure. In this way the lower furnace can operate at pressure low enough (below 62 bar) that corrosion is manageable. The lower furnace has its own drum and a separate water circuit.
The upper furnace design, meanwhile, uncouples it from the lower furnace allowing it to be operated at pressure where a reheat cycle becomes practical, typically greater than 172 bar (2,400 psi). To improve steam cycle efficiency, the lower furnace’s low-pressure steam is used for feedwater heat. This converts the low-pressure steam energy to high-pressure steam that can be used in a high-pressure turbine. Low-pressure feedwater heating required the use of “gas over tube” tubular airheaters to keep the exit gas temperature low and maintain boiler efficiency. Since a tubular airheater’s air side is lower than traditional feedwater temperatures, lower exit gas temperatures and higher boiler efficiencies can be achieved.
From a mill owner’s perspective, the reheat recovery boiler can reduce overall electricity purchases and potentially develop a new revenue stream as a net energy producer. Hicks says the revenue potential could be further enhanced through green power sales. He says a utility buying power from a pulp mill may be eligible to satisfy state renewable portfolio standard requirements, enhancing the mill’s electric power market appeal.David Wagman
Energy Composites Corp., a Wisconsin-based wind power manufacturer, plans to build a $15 million wind turbine blade factory capable of producing up to 1,500 blades a year by 2010. The local government and the company expect to reach a final agreement before June 1, after which Energy Composites will begin construction.
Ongoing uncertainty in state and federal policies and the economy caused Tri-State Generation and Transmission Association to revisit its long-term resource plan, which included options for new coal-based generating units. Colorado-based Tri-State will evaluate energy efficiency, renewable energy, natural gas, clean coal and nuclear technology as part of its long-term planning process. Energy policy uncertainty affected the association’s proposed coal-based generation project in Kansas when a construction permit was denied for a plant in 2007.
After a scientific review ordered in 2007 by the U.S. Supreme Court, the Environmental Protection Agency issued a proposed finding that greenhouse gases contribute to air pollution that may endanger public health or welfare. The proposed finding, which now moves to a public comment period, identified six greenhouse gases that pose a potential threat carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulfur hexafluoride.
The finding now enters the public comment period, which is the next step in the deliberative process EPA must undertake before issuing final findings.
The finding does not include any proposed regulations. EPA Administrator Lisa Jackson and the Obama administration have both indicated their preference for comprehensive legislation to address this issue rather than regulation through the Clean Air Act.
Drilling nears completion in Illinois for a well that will store up to 1 million metric tons of carbon dioxide beginning next year. The demonstration project will store CO2 emitted from the Archer Daniels Midland ethanol production facility. The gas will be injected more than a mile beneath the surface into a deep saline formation. Following injection, the site will be monitored. Results will provide information on the future of carbon sequestration as a viable option for CO2 storage from facilities including power plants. The U.S. Department of Energy and the Illinois Department of Commerce and Economic Opportunity are funding the project. Drilling operations at the site began in February.
For news headlines updated throughout the business day, visit Power Engineering online at www.power-eng.com.
Projects & Contracts
PPL Corp. will file with the Federal Energy Regulatory Commission for a 125 MW expansion project at the Holtwood hydroelectric plant on the Susquehanna River in Pennsylvania. PPL withdrew an initial application to expand capacity at the same site in December, citing economic concerns, energy prices and tightening credit markets. The estimated $440 million project is subject to FERC approval, stimulus funding availability and contract negotiation. Construction could start in February 2010. PPL reconsidered the project in view of the tax incentives and potential loan guarantees for renewable energy projects in the federal economic stimulus package.
The Shaw Group’s nuclear unit and Westinghouse Electric Co. received full notice to proceed from Southern Nuclear, a unit of Southern Co., on its engineering, procurement and construction contract for two Westinghouse AP1000 nuclear power units and related facilities. The contract was first announced in April 2008. This past March 17, Georgia regulators certified Southern Co. unit Georgia Power Co. to build Units 3 and 4 at the existing Vogtle Electric Generating Plant. Oglethorpe Power, Municipal Electric Authority of Georgia and Dalton Utilities also own the plant.
The Shaw Group’s maintenance division renewed its existing contract with Entergy Nuclear, a unit of Entergy Corp., to provide nuclear maintenance services to 11 nuclear units at nine power stations. Shaw’s scope of work includes maintenance and modifications, refueling outage services and capital construction. The value of Shaw’s six-year contract, which will be included in the company’s third quarter backlog of unfilled orders, was not disclosed.
Sempra Generation plans to build at least 300 MW of solar power projects on land it owns in Arizona. Construction could start next year. Sempra plans to build solar projects on 4,000 acres near Phoenix, where it also already has a 1,250 MW natural gas power plant. The Arizona solar plant, called Mesquite Solar, would be built over many years. The company did not say how much money it would spend on the plan or the size of the first project.
FirstEnergy Corp. plans to retrofit units 4 and 5 at its coal-fired R.E. Burger Plant in Ohio to generate power with biomass. The project will cost about $200 million and will not change the plant’s current 312 MW capacity. FirstEnergy said the project will feature a closed-loop system, using biomass derived from an energy crop grown specifically for use as a fuel source. This energy crop would act as a carbon sink, removing as much carbon dioxide from the environment when it is growing as it releases when it is burned. The company found that burning principally with biomass would produce lower emissions overall than retrofitting the plant with a scrubber.
Dominion Virginia Power won approval from the Virginia State Corporation Commission for a 580 MW power station. The $619 million, combined-cycle Bear Garden Power Station will be fueled by natural gas with oil as a backup. The plant will cost around $1,067/kw to build. Bear Garden will be a 2-on-1 unit, in which two combustion turbines generate electricity and exhaust heat produces steam to generate additional electricity. The plant is scheduled to begin operation by summer 2011.
Alstom and Dow Chemical Co. will design and build a plant to capture CO2 from the flue gas of a coal-fired boiler at a Dow-owned facility in South Charleston, W.V. Alstom will design, build and operate the plant, which is expected to capture around 1,800 tons a year of CO2 from flue gas using Alstom’s and Dow’s amine technology. Dow will provide the site and utilities, as well as the chemicals and its amine technology for this project. The pilot plant is expected to come online by the third quarter. All the coal used in the pilot will be sourced locally in West Virginia.
Areva Enrichment Services plans to double the capacity of its Eagle Rock uranium enrichment plant to 6.6 separative work units (SWU) a year. The company told the Nuclear Regulatory Commission it would revise the application to double the plant’s capacity from an originally planned 3.3 million SWU. Areva decided to revise the application to give it flexibility to build a bigger plant if market conditions warrant. If approved, full capacity production would occur in 2022, four years later than under the original application.
Tenaska chose construction firm Kiewit Energy Co. and engineering firm Burns & McDonnell for the front end engineering and design (FEED) study and facility cost report for the $3.5 billion Taylorville Energy Center. Independent power producer Tenaska will issue more contracts for technology licenses and process design work required for the study within the next 60 days. Tenaska hopes to start construction in 2010 after the report is approved. Taylorville will be a commercial-scale, coal gasification plant with carbon capture. Its technology will convert coal into substitute natural gas, which can be used for electricity generation or fed into the interstate natural gas pipeline system.
For news headlines updated throughout the business day, visit Power Engineering online at www.power-eng.com.
People & Personnel
Larry T. Borgard, president and COO of Integrys Gas Group, was named president and COOUtilities, taking on the roles of president and CEO of Wisconsin Public Service and CEO of Upper Peninsula Power Co. Borgard has more than 24 years in the energy industry. He has served as leader of the Integrys Gas Group since the company was formed in early 2007. He began his career with Wisconsin Public Service in 1984. He received a Bachelor of Science degree in Electrical Engineering from Michigan State University and a Master’s degree in Business Administration from the University of Wisconsin-Oshkosh.
Pacific Gas and Electric Co. named John T. Conway to head the utility’s newly created Energy Supply organization. Conway will lead PG&E’s previously separate power generation and power procurement functions as senior vice president-energy supply and chief nuclear officer. Within the new organization, Fong Wan, senior vice president-energy procurement, will continue to be responsible for managing PG&E’s portfolio of power supply contracts with other generators. He will report to Conway. PG&E also appointed Steven E. Malnight, vice president, renewable energy, to oversee the company’s emerging utility-owned renewable business and ongoing renewable energy contracting. This newly created position will report to Wan.
For news headlines updated throughout the business day, visit Power Engineering online at www.power-eng.com.
Mergers & Aquisitions
NV Energy unit Sierra Pacific Power Co. will sell its California electric generation and distribution assets for $116 million. The buyer is California Pacific Electric Co. (Calpeco), a newly formed company jointly owned by Algonquin Power Income Fund and Emera Inc. Calpeco will acquire the California distribution and related generation assets of Sierra Pacific, which owns a newly re-powered 12 MW generation plant and provides distribution service to about 47,000 customers. The agreement includes a premium on the book value of net rate base assets, plus working capital to be determined at the date of closing. The companies expect the transaction to close in 2010, following California and Nevada state regulatory and Federal Energy Regulatory Commission approvals, and clearance under antitrust laws. Algonquin Power owns and operates utility assets across North America including 42 renewable energy facilities and 11 thermal energy facilities representing more than 400 MW of installed capacity. Emera Inc. owns Nova Scotia Power and Bangor Hydro-Electric and has a joint venture interest in the 600 MW Bear Swamp pumped storage hydroelectric plant in Massachusetts.