BUSINESS AND TECHNOLOGY FOR THE GLOBAL GENERATION INDUSTRY

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Vol. 152 • No. 1 • January 2008www.powermag.com

Industry prognosis for 2008: Carbon paralysis

Applying water-stingy technologies

Eliminate oil whip vibration in steam turbines

Protect plant equipment from voltage sags

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January 2008 | POWER www.powermag.com 1

Established 1882 • Vol. 152 • No. 1 January 2008

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COVER STORY: 2008 INDUSTRY FORECAST 28 Regulatory risks paralyzing power industry while demand grows

As this issue’s cover announces, 2008 will be the year the generation industry grap-ples with CO2 emissions. Project developers are suddenly coal-shy, mostly flirting with new nukes, waiting impatiently in line for equipment manufacturers to catch up with the demand for wind turbines, and finding gas more attractive again. With no proven greenhouse gas sequestration technology on the horizon, utilities will be playing it safe with energy-efficiency ploys rather than rushing to contract for much-needed new generation.

40 Greater fuel diversity needed to meet growing U.S. electricity demandOblivious to industry uncertainties, electricity demand is growing, and one of the best ways to manage the uncertainty is to diversify fuel sources to ensure supply reliability. That’s just one reason the outlook for renewables is rosy this year. Check out Industrial Info Resources’ detailed data tables showing actual and planned gen-eration projects of all fuel types.

SPECIAL REPORT WATER MANAGEMENT

46 Costlier, scarcer supplies dictate making thermal plants less thirstyThe largest percentage of new U.S. generation capacity is anticipated to be located in arid regions, where a gallon of water saved goes straight to the bottom line while ensuring the sustainability of both future plant operations and a growing economy. The author of an EPRI report on the subject provides a rundown of potential cost sav-ings for several available conservation technologies.

FEATURES STEAM TURBINES 51 Eliminating oil whip–induced vibration after a steam turbine retrofit

You can’t anticipate the unexpected—like vibration problems that cause a trip right after a successful retrofit project. But you can learn from this case study how to troubleshoot such situations.

POWER QUALITY 56 Protecting plant equipment from voltage sags

Voltage sag is a compatibility problem with at least two classes of solutions: You can improve the power or you can make the equipment tougher. The latter approach is called “voltage sag immunity,” and equipment manufacturers have several com-pliance standards that you should be aware of when specifying future equipment purchases.

MANAGEMENT 60 Workforce analysis: Replacing management by fad with management certainty

So how do you get your arms around the workforce challenges of your organization? Start with a workforce analysis. It’s relatively fast, affordable, and—most important—tailored to your team.

DEPARTMENTS 4 SPEAKING OF POWER

6 GLOBAL MONITOR 6 Dominion applies for new Virginia

reactor 6 ABB commissions world’s largest

SVC 8 Google Earth adds air quality data 8 Alstom supplies integrated solar/CC

project in Morocco 10 DOE updates coal plant database 10 Dam the Red Sea? 14 Complying with CWA Section 316 17 POWER digest

20 FOCUS ON O&M 20 Single-window control of CHP

plant’s energy converters 22 Safety stuffers entertain as they

inform 24 Doubling up for a heavy load

26 LEGAL & REGULATORY

62 NEW PRODUCTS

72 COMMENTARY

On the coverHow quickly CO2 will become the most im-portant emissions risk to manage is anyone’s guess, but everyone anticipates that regula-tors at all levels, plus public pressure, will be turning up the heat on power producers to mitigate this greenhouse gas’s risks. Cover image by Mark Cavich.

www.powermag.com POWER | January 20082

Now incorporating and

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www.powermag.com POWER | January 20084

SPEAKING OF POWER

Renew Indian Point’s fission license

Early last month, Governor Eliot Spitzer and Attorney General Andrew M. Cuomo—both New York Democrats—asked the U.S. Nuclear Regulatory Commission (NRC) to reject Entergy

Nuclear’s application to extend the operating licenses of Indian Point Units 2 and 3 for 20 years. The units, each rated at about 1,000 MW, are a major source of power for New York City, 35 miles to the south, and points north. Unit 1 was decommis-sioned in 1974.

Citing numerous potential safety issues and past safety prob-lems at the nuclear plant, Spitzer and Cuomo said they don’t just want the two units to be shut down when their current licenses expire in September 2013 (Unit 2) and December 2015 (Unit 3). Cuomo said, “Indian Point should . . . be closed now . . . in my opinion, [it is] a catastrophe waiting to happen.”

The Atomic Safety Licensing Board (ASLB), comprising three administrative law judges, is expected to decide by March 2008 whether New York State can intervene in the relicensing process by raising issues it thinks the NRC should consider.

Bait the hookThe Cuomo-Spitzer petition was second-page news for most of the country, but the announcement drove energy and environ-mental bloggers on both sides of the political see-saw into a frenzy. Opposing Indian Point is a perennial favorite for local and state politicians pandering for votes. But I suspect Cuomo and Spitzer know the ultimate fate of their 313-page petition.

Indian Point Energy Center, originally owned by Consolidated Edison (Unit 2) and the New York Power Authority (Unit 3), was purchased by Entergy Nuclear Northeast just over six years ago. After Entergy submitted a relicensing application covering both units in May 2007, Cuomo’s lawyers began working overtime.

But their efforts may have been in vain because the NRC has approved every one of the 48 nuclear-unit relicensing requests it has received to date. The process typically takes 22 to 30 months and includes parallel-track reviews of whether the reactor can continue to be operated safely and whether the plant can con-tinue to protect the environment over the 20-year license term. By law, those are the only two areas that the NRC is required to review.

Although the agency prepares an environmental impact state-ment (EIS) for each license renewal, as required by the National Environmental Policy Act of 1969 (NEPA), it’s not a full-blown EIS. The NRC has prepared a Generic Environmental Impact Statement for License Renewal of Nuclear Plants (GEIS) that as-sesses environmental issues common to all 104 nuclear stations

operating in the U.S. Entergy must assess environmental issues at Indian Point that are at odds with the GEIS as well as other site-specific issues.

What’s more, NEPA does not require the NRC to perform an environmental review of a unit’s existing operating license. It does, however, mandate that the NRC make a studied assessment of “reasonable alternatives [including] those that are practical or feasible from a technical and economic standpoint.” NEPA says this assessment must be developed “using common sense rather than [being] simply desirable from the standpoint of the applicant” and must “include the alternative of no action.” In other words, the process takes into account how a unit will be expected to perform in the future, not how it has performed in the past.

Throw the lineThis is where the review process begins to look murky to those not familiar with nuclear plant relicensing. The safety of opera-tions, a site’s emergency preparedness, and potential acts of ter-rorism are not considered by the environmental review process. Nor are issues related to the storage or disposal of high-level nuclear waste on plant property germane to the overall relicens-ing process.

Because every one of the issues raised by Spitzer and Cuomo is beyond the scope of the process, I expect the ALSB will deny the request to have the NRC consider them. If that happens, the New Yorkers could file in Federal Court to keep their stance in the public eye, possibly improving prospects for Democrats this national election year. But I suspect that they will lose in that venue, too. Using the courts to stretch out the relicensing process won’t help get Indian Point shut down now. NRC rules state that if a relicensing application is filed five years before a unit’s original license is set to expire, it can continue to operate until the NRC rules on the extension request. New York politics is a contact sport, and the tag team of Spitzer and Cuomo has put on its game face.

Reel ’em inHere’s how you can tell the petition is just a political red her-ring: No opponent of Indian Point has proposed concrete ways to replace the plant’s 2,000-MW generating capacity, which sup-plies 11.5% of New York State’s electricity demand.

Indian Point operated with a 93% capacity factor last year. The Nuclear Energy Institute notes that the average wholesale cost of nuclear power in the U.S. is a low 1.72 cents/kWh. In the densely populated U.S. northeast and mid-Atlantic states, where building anything that makes electricity is anathema, economic baseload replacement power alternatives simply do not exist.

But then I have to remind myself that ensuring the region has an affordable and reliable electricity supply is not part of the re-actor relicensing process. Should it be? I invite your opinions. ■

—Dr. Robert Peltier, PEEditor-in-Chief

Opposing Indian Point is a perennial favorite for local and state politicians pandering for votes.

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www.powermag.com POWER | January 20086

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Dominion applies for new Virginia reactorIn late November, Dominion became the third power company to formally propose building what would be the first new U.S. nuclear unit in more than 30 years when it filed an application for a combined construction and operating license (COL) license with the Nuclear Regulatory Com-mission. The reactor would be construct-ed on the grounds of Dominion’s North Anna nuclear plant (Figure 1) in Louisa County, Va. North Anna is already home to two reactors with a combined capacity of 1,834 MW.

If the approval process goes smoothly, Dominion could break ground by 2010 and have the new unit on-line by 2015. It would be based on the 1,520-MW GE-Hitachi Economic Simplified Boiling Water Reactor (ESBWR) design. With the filing, Dominion becomes the first U.S. investor-owned, regulated utility to submit a full COL application.

Exelon Nuclear earlier announced plans to use the ESBWR for a plant it is consid-ering building in Texas. The company is studying locations in Matagorda and Vic-toria Counties as potential sites.

Like most utilities considering building new nuclear capacity, Dominion has spread the financial risk of the North Anna proj-ect across several partners. Dominion will pay only about $60 million of the $500 million needed to reach the construction phase in Virginia. The balance will be paid by project partners, which include GE-Hitachi and Bechtel Corp., and by the Department of Energy (DOE) under a coop-erative agreement to have the North Anna project serve as a “reference” application for other utilities considering applying to build an ESBWR.

A second utility consortium, NuStart Energy Development LLC, is working with the DOE under a similar agreement to develop a reference COL application for Westinghouse AP1000 reactors.

ABB commissions world’s largest SVCIn early December, ABB announced that it had completed work on what is now the world’s largest static VAR (volt-amperes reactive) compensator (SVC).

The SVC, which entered service on De-cember 5, is at Allegheny Power’s Black Oak Substation near Rawlings, Md. (Figure 2). The unit will enhance the reliability of Allegheny’s 500-kV Black Oak-Bed-dington transmission line—one of the most congested on the Pennsylvania-New Jersey-Maryland (PJM) Interconnection network—by quickly changing reactive power levels to stabilize line voltage. The SVC also will boost transmission capac-ity on multiple 500-kV lines in the PJM region.

The Black Oak installation uses ABB’s MACH 2 control system both to manage the operation of the SVC and to switch on and off the 500-kV capacitor banks on the lines entering and leaving the substation.

The project was initiated as part of PJM’s regional transmission expansion plan to identify the upgrades and additions needed to ensure reliability of its multi-state transmission system. “The Black Oak SVC will benefit millions of customers by providing a new level of reliability to a critical transmission line serving the Mid-Atlantic region,” said David E. Flitman, president of Allegheny Power. “Further, allowing more power to flow on existing lines is an important step in keeping pace with the region’s increased demand for electricity.”

The Black Oak SVC turnkey project was completed in just 14 months—no mean feat, given its size, complexity, and scope. “Collaboration was essential to meeting the aggressive timeline,” said Flitman. “If it were not for the Allegheny and ABB

1. Virginia is for nuke lovers. Dominion has applied for a combined construction and operating license for a third unit at its North Anna nuclear facility in Virginia. Courtesy: Dominion

2. VAR sets record. ABB recently com-missioned the world’s largest static VAR compensator at Allegheny Power’s Black Oak substation. Courtesy: ABB

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POWER | January 20088

teams working so closely together, we simply would not have been able to get the system on-line this quickly.”

Google Earth adds air quality dataWe’ve all done it—fired up Google Earth and zoomed in on our home or a famous landmark to see how sharp satellite photos have become. You still can’t read license plates, but the view from space is captivating, and “flying” from one target to an-other is a trip.

Google recently integrated near-real-time scientific air qual-ity information from the U.S. Environmental Protection Agency (EPA) directly into Google Earth. The program accesses the EPA’s AIRNow database hourly, enabling its new Air Quality Index to display current air quality conditions at any U.S. location. Figure 3 shows two readings for Phoenix called up a month ago.

For more information on AIRNow, and easy instructions for using it with Google Earth, go to www.epa.gov/region09/air/airnow.

Alstom supplies integrated solar/CC project in Morocco In late October, Alstom was awarded a $234 million contract by Spain’s Abengoa Group, on behalf of Morocco’s Office National d’Électricité, to supply two GT13E2 gas turbine generators, one steam turbine generator, and three air-cooled turbogenerators to the Aïn Béni Mathar power project. The deal includes a 21-year service contract under which Alstom will maintain and help sup-port the operation of the plant, 60 miles from Oujda.

The project seeks to become the world’s first integrated solar combined-cycle power plant. It will have a generating capacity of about 470 MW, 20 MW of which will come from energy col-lected by a 1.97 million ft2 array of single-axis-tracking cylindri-cal parabolic mirrors in parallel rows. Abengoa Group received a $43 million grant from the World Bank to develop the solar part of the project.

On the solar side, each bank of mirrors is equipped with a lin-ear parabolic reflector that aims reflected sunlight on a receiver at the focus of the bank’s parabola. The energy delivered to the receiver heats a working fluid that’s circulated through it. A se-ries of heat exchangers extracts the energy and feeds it to two heat-recovery steam generators (HRSGs) into which the two gas turbines exhaust (Figure 4).

As the figure shows, the two gas turbine generators are part of a conventional 2 x 1 combined-cycle configuration. The two

3. Air Google. Thanks to a partnership with the U.S. EPA, users of Google Earth can now call up near-real-time air quality data for any location in America. Source: Google Earth

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POWER | January 200810

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systems are tightly integrated: Water used in the solar side’s steam generator is taken from the HRSG’s economizers, and steam generated by the solar field is injected into the superheaters of the same HRSGs. Both flows of steam, generated by the so-lar field and by the HRSGs, are expanded together by the single steam turbine.

DOE updates coal plant databaseInterested in a comprehensive and current list of U.S. coal plants and projects? Check out the latest release of the DOE’s 2007 Coal Power Plant Database. Available as an 8.6-MB Excel spreadsheet, a 20.8-MB Excel pivot table, or a 24-MB Access database, it is maintained by the Office of Fossil Energy’s National Energy Technology Laboratory. The database, covering more than 1,900 plants, can be found at www.netl.doe.gov/energy-analyses/technology.html.

Dam the Red Sea?Building a dam across the Red Sea at Bab al Mandab (“Bab El Mandeb” on Figure 5), the 20-mile-wide strait separating Yemen and Djibouti, and using it to generate hydropower could help meet the growing electricity demand of millions of people in

4. Technology fusion. A simplified block diagram of the 470-MW integrated solar com-bined-cycle plant that Alstom is building in Morocco. Source: Alstom

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POWER | January 200812

5. Moses crossed another way, at the other end. Researchers at Utrecht Uni-versity in The Netherlands suggest that 50 GW could be generated by a 20-mile-wide dam across the Red Sea near its southern end. Courtesy: NASA

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the Middle East without further depleting the region’s oil and natural gas reserves. But such a massive engineering project also could take a ruinous toll on the local environment and displace countless people from their homes.

Those are the overall conclusions of a research report recently published in the International Journal of Global Environmental Issues, from Inderscience Publishers. In the report, Roelof Dirk Schuiling of Holland’s Utrecht University and his colleagues dis-cuss the costs and benefits of what could be the most ambitious engineering project ever.

According to the authors, existing technology allows us to shift and shape the earth on a relatively large scale, including damming rivers to create artificial lakes big enough for mega-watt-scale power generation. In the near future, it may even be possible to dam the Red Sea. Such a barrier would stem the flow of seawater from the Indian Ocean into the sea, which is highly evaporative.

Schuiling, a geochemical engineer, says that a dam at Bab al Mandab could be used to generate as much as 50 GW. By comparison, the 33 hydroelectricity generators at Grand Cou-lee Dam on the Columbia River in central Washington have a peak summer capacity of 7.1 GW, making it the largest power plant in the U.S., according to the DOE’s Energy Information Administration.

“Such a project will dramatically affect the region’s econo-my, political situation and ecology, and the effects may be felt well beyond the physical and political limits of the project,” the authors say of the dam. For example, it would cause major disruptions to military and commercial ship traffic (Figure 6).

Schuiling and his colleagues wrote that the costs and time frames of such a massive project are way beyond normal eco-nomic considerations. However, someone is sure to at least consider it, because 50 GW of hydro capacity would offer fu-ture generations a sustainable, CO2-free alternative to the con-tinued burning of huge quantities of fossil fuels.

Complying with CWA Section 316In October 2007, more than 100 people met at the headquar-ters of Tri-State Generation and Transmission Association in Westminster, Colo., for an EPRI-sponsored workshop on Sec-tion 316(a) of the Clean Water Act (CWA). This section of the CWA regulates the thermal effluents of once-through power plant cooling systems. It provides for variances from both technology-based limits and water quality standards if a plant can demonstrate that its thermal discharge “will assure the protection and propagation of a balanced, indigenous popula-

6. Five acres of diplomacy. Building a dam that would put an end to all ship traffic, including oil supertankers, into and out of the Red Sea would definitely not be popular with the energy-hungry industrial-ized world. Courtesy: DefenseLink

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GLOBAL MONITOR

January 2008 | POWER 15

tion of shellfish, fish, and wildlife in and on that body of water.” The 316(a) program was very active in the 1970s, when thermal dischargers conducted studies to determine whether they quali-fied for a variance.

“Even if the Clean Water Act has not changed in 35 years, the world has and continues to do so,” said Dr. Robert Goldstein, a senior technical executive of EPRI. “Water issues such as thermal discharge, impingement and entrainment, total maximum daily loads, effluent guidelines, and availability are converging. We have come together as a concerned community of power plant employees, regulators, consultants, researchers, professors, and students to consider a mixture of old and new topics that excite the imagination and call out for creative scientific, technical, and policy solutions.”

It ain’t broke—it’s just stale. Over two days, attendees heard more than 25 presentations on 316(a) from technical, legal, and regulatory perspectives. Among the technical topics covered were the development of water quality and thermal standards, thermal response characterization, thermal modeling, recent advances in cooling technologies, and the interplay between 316(a) and 316(b).

Some speakers discussed 316(a) from more than one perspec-tive. For example, keynoter Chuck Coutant provided an overview of the past 60 years of attempts to set temperature criteria and standards to protect aquatic life. He pointed out that although regulatory efforts to control potential adverse effects from ther-mal discharges have been ongoing since the mid-1960s, there is no consistent framework within which states develop and imple-ment protective water temperature quality criteria.

Deborah Nagel, industrial branch chief of the EPA’s Water Per-mits division, discussed the specific requirements of applications for a 316(a) variance. She also said that, from the agency’s per-spective, state permitting authorities are not implementing the section consistently or correctly.

To improve the situation, the EPA expects to update its 316(a) technical guidance document, originally drafted in 1977, soon. “The 316(a) guidance manual has served us well for 30 years, but it is certainly due for updating,” said Chuck Coutant. “The basic structure of using retrospective (no prior harm) and predictive (thermal requirement data for organisms) approaches for demon-strating a balanced community remains strong. But the guidance needs to [reflect] a number of administrative and judicial deci-sions [since 1977], such as including managed, non-indigenous fish species and not expecting a return to pristine conditions. Also, several indices of community health have been developed that are very useful for evaluating the balance of aquatic com-munities, which is the crux of Section 316(a).”

While the EPA works toward updating the guidance document, several states are making an effort to revise long-outdated wa-ter temperature standards. Presentations by Erich Emery of the Ohio River Valley Water Sanitation Commission (whose members represent Illinois, Indiana, Kentucky, New York, Ohio, Pennsylva-nia, Virginia, and West Virginia), Lareina Wall of Colorado-based GEI Consultants, and Mike Wenholz of Wisconsin’s Department of Natural Resources discussed the status of updates to thermal standards in their respective states.

Research updates. Several workshop presentations updated scientific research on thermal response characterization. Rob Reash of American Electric Power discussed the issues involved in comparing laboratory and field tolerances for fish. Tamara Pandolfo of North Carolina State University presented her data on freshwater mussel sensitivity to a range of water tempera-tures, which showed that the presence of a secondary toxicant

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can make mussels more sensitive to tem-perature stress. Telemetry and other state-of-the-art tools for evaluating impacts of thermal discharges on fish were presented by Tim Brush of Normandeau Associates.

One-third of the presentations consisted of recent, site-specific case studies. Terry Cheek of Geosyntec Consultants and Bill Evans of Georgia Power described the driv-ers of Georgia Power’s decision to retrofit the cooling towers of three of its plants to prevent fish kills under extreme condi-tions, and the implications of doing so on the viability of the 316(a) regulatory op-tion. David Lee of We Energies shared the 316(a) demonstration process, including thermal plume modeling, used to prepare the Oak Creek Expansion Project’s Wiscon-sin Pollutant Discharge Elimination Sys-tem (WPDES) permit application.

The conference took on an interna-tional flavor as folks from France, the Netherlands, and New Zealand discussed their countries’ plant cooling water poli-cies. Yves Souchon of Cemagref, a French public research institute focusing on land management issues, and Cecile Delattre of Électricité de France presented a summary of the thermal discharge regulations in their nation and some results of biological

monitoring at power plant sites. Maarten Bruijs of the Dutch consultant KEMA de-scribed a field study on the influence on fish behavior of higher water temperatures in the cooling water discharge of Claus Power Plant in the Netherlands. Finally, Jacques Boubee of the National Institute of Water and Atmospheric Research sum-marized New Zealand’s generation and en-vironmental regulations and the challenges in meeting them at Huntly Power Station, the country’s biggest thermal plant.

Hot topic. A common theme of many presentations was the effect of climate change on plant environments. For ex-ample, Yves Souchon and Cecile Delattre explained that Europe’s heat wave of 2003 raised questions that France’s environ-mental policymakers are still struggling to answer. As for climate change’s effect in the U.S., Deborah Nagle of the EPA said it was creating more areas with prolonged dry and wet conditions and generally in-creasing the ambient temperatures of wa-terbodies.

The workshop closed with several pre-sentations on emerging issues and future research needs. E. Eric Adams of MIT dis-cussed advances in thermal plume mod-eling. Judson White and John Waddill of

Dominion Resources explained the per-formance rationale for hybrid cooling, called for in their company’s recent COL application for a proposed new unit at the North Anna nuclear station (see p. 6). Tim Hogan of Alden Research Laboratory dis-cussed the benefits of colocating power plants with desalination or liquefied natu-ral gas facilities. In such arrangements, the power plant’s discharge can serve as the water supply for either type of facility, thereby reducing costs and enabling the sharing of research, construction, permit-ting, and monitoring resources.

The workshop was organized by a steer-ing committee consisting of Chuck Cout-ant (retired); Doug Dixon and Robert Goldstein of EPRI; Raymond Harrell and Ron Lewis of Duke Energy; Chantell John-son of the host (Tri-State); Christine Lew and Bill Mills of Tetra Tech; Dave Michaud of We Energies; and Rob Reash of Ameri-can Electric Power.

EPRI will publish the workshop proceed-ings early this year. For more information, contact Robert Goldstein at rogoldst@epri.com.

—Christine Lew, PE, a senior environ-mental engineer for Tetra Tech Inc.

(www.teratech.com).

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January 2008 | POWER 17

POWER digestNews items of interest to power industry professionals.

Big CC plant coming to Texas. In early December, Panda Energy Inc. announced its intention to build, own, and operate a 1,000-MW combined-cycle plant in an industrial area of Temple, Texas, on Inter-state 35 between Waco and Austin. The area is one of the 10 densest and fast-est-growing population centers in the U.S. Nearly half of the state’s 21 million citi-zens live within 50 miles of I-35.

“This plant will help meet the future energy needs of our growing state and strengthen the economy of central Texas” said Robert Carter, Panda Energy’s chair-man and CEO. “With little or no power plant construction having occurred during the past five years, state and local offi-cials are being farsighted in working now to enhance the future reliability of the region’s power supply. We look forward to working with them in bringing this project to completion.”

Panda told POWER that it is deciding be-tween two different configurations for the gas-fired plant. One option is a Siemens Power Generation FlexPlant10, using SCC6-5000F combustion turbine generators in combined-cycle mode, with four 1 x 1 power blocks. The other is a General Elec-tric Frame 7FA-based plant with two 2 x 1 power blocks. Panda noted that the choice will depend on the units’ availability and other market factors when the time comes to specify major equipment.

Temple Generating Station will be locat-ed on a 250-acre site at the South Temple Industrial Park. It should take about two years to build, assuming timely receipt of regulatory approvals and financing. Panda has already filed for an air permit with the Texas Commission on Environmental Qual-ity. The company says it is designing the plant to maximize the use of reclaimed water, thereby conserving the state’s fresh water resources.

North Dakota to get new gasification plant. The North Dakota Industrial Com-mission and representatives of Great Northern Power Development LP (GNPD) and Allied Syngas Corp. have announced a $1.4 billion coal gasification project at South Heart that would produce pipeline-quality syngas.

The South Heart project would be a joint venture of GNPD and Allied. Both companies have subsidiaries that bring strategic value to the table. For example, Great Northern Properties LP, a GNPD af-filiate, owns a substantial amount of the coal reserves that would fuel the plant.

Meanwhile, Allied’s Envirotherm GmbHaffiliate is a co-owner of the advanced British Gas Lurgi (BGL) gasification tech-nology that the project would use. BGL’s other owner is Advantica Ltd. Advantica and Envirotherm will provide the technol-ogy license, design, and technical support for the gasification process.

The project will use seven BGL gasifiers to turn North Dakota lignite into as much as 100 million cubic feet/day of pipeline-quality gas that could be sold locally or nationwide. According to the project partners, the gasification plant will also produce many of the chemical by-products needed to manufacture fertilizers or serve as feedstocks for chemical plants. This project also will capture CO2, which could then be sequestered in underground brine or shale formations in and near North Da-kota or used to enhance recovery of oil from nearly depleted nearby fields.

Construction is slated to begin in late 2009 or early 2010 and wrap up in 2012.

NRG, Powerspan announce large-scale CCS demo. In a recently announced memorandum of understanding NRG En-ergy Inc. and Powerspan Corp. agreed to demonstrate at commercial scale the latter’s ECO2 technology for carbon cap-ture and sequestration (CCS). (See POWER, October 2007, p. 54, for details of the ECO2 process.)

ECO2 is a post-combustion, regenerative process that uses an ammonia-based solu-tion to capture CO2 from the flue gas of a power plant. Once the greenhouse gas has been captured, the solution is regen-erated to release CO2 and ammonia. The ammonia is then sent back to the scrub-bing process, leaving the CO2 in a form suitable for geological storage. Ammonia is not consumed by the scrubbing process, which creates no by-products. Powerspan says ECO2 technology is applicable to both existing and new coal-fired plants and is particularly economical for plants that use ammonia to reduce their NOx emissions.

To date, CCS demos have only been conducted on pilot-scale coal plants with capacities between 1 MW and 5 MW. This demo will take place at NRG’s W.A. Parish plant near Sugar Land, Texas, on quantities of flue gas equal to those of a 125-MW unit. The project’s goal is to capture and seques-ter about one million tons of CO2 annually.

As at the South Heart project, the CO2 captured by the Parish project may be used to enhance oilfield recovery operations in the region. The demonstration facility, which is being designed to remove 90% of the CO2 from a flue gas stream, is expected to be operational in 2012. ■

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The new facility will allow us to double the size of the Mitsubishi team here to support you, as well as to significantlyexpand our parts supply inventorystanding behind your operating fleet.

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Untitled-2 1 1/2/08 12:39:16 PM

www.mpshq.com

2001DedicatedService inthe WesternHemisphere

2008ExpandedWorldwideSupply ofCritical Parts

Power Generation Services - Blade and Vane Manufacturing Center of Excellence

Since 2001, MPSA has providedOEM-quality power generationequipment and maintenance service support for both Mitsubishi andnon-Mitsubishi turbine users.

At our Orlando Service Center, we’ve continually extended theboundaries of repair and manufacturing services for rotating and stationary components of advanced-frame turbines.

enhancing systems, and “lean”manufacturing techniques designedto ensure best-quality and rapidavailability of both gas and steamturbine parts.

The new facility will allow us to double the size of the Mitsubishi team here to support you, as well as to significantlyexpand our parts supply inventorystanding behind your operating fleet.

In fact, with expert turnkey projectmanagement, engineering, outage and O&M support – coupled with anexpansive critical spares inventory for advanced-frame D-, F- and G-Class gas turbines, plus techniques to assess and extend component life – we’ve redefined service expectations forcustomers throughout the Americas.

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Once online in the second quarter of 2008, our new factory will give MPSA the most modern and comprehen-sive manufacturing capability in the hemisphere – with highly automated machining operations, productivity-

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OSC Spread.indd 1 12/21/07 5:25:26 AM

Untitled-2 2 1/2/08 12:39:27 PM

www.powermag.com POWER | January 200820

FOCUS ON O&M FOCUS ON O&M FOCUS ON O&M FOCUS ON O&M FOCUS ON O&M FOCUS ON O&M FOCUS ON O&M FOCUS ON O&M FOCUS ON O&M FOCUS ON O&M FOCUS ON O&M FOCUS ON O&M FOCUS ON O&M FOCUS ON O&M FOCUS ON O&M FOCUS ON O&M FOCUS ON O&M FOCUS ON O&M FOCUS ON O&M FOCUS ON O&M FOCUS ON O&M FOCUS ON O&M FOCUS ON O&M

FOCUS ON O&MINSTRUMENTATION & CONTROL

Single-window control of CHP plant’s energy convertersIn February 2005, APS Energy Services and its Northwind Phoenix subsidiary to-gether began building a gas-fired com-bined heat and power (CHP) plant on the campus of Arizona State University (ASU) in Tempe. Northwind markets, develops, designs, finances, constructs, and oper-ates district-heating plants throughout Arizona.

Phase I of the ASU plant is now on-line. It has five 2,000-ton water chillers (Figure 1) from York (www.york.com), a 7.2-MW natural gas–fired combustion tur-bine (CT) from Solar Turbines Inc. (mysolar.cat.com), a 2-MW Murray steam turbine (www.dresser-rand.com), an 80,000-lb/hr heat-recovery steam generator (HRSG) from Rentech Boiler Systems Inc. (www.rentechboilers.com) equipped with a Coen duct burner management system (www.coan.com), and a pair of 2-MW diesel en-gine generators from Cummins Power Gen-eration Inc. (www.cumminspower.com).

Subsequent construction phases will more than double the chilled water ca-pacity and increase the power and steam outputs of the cogeneration system to levels suitable for supplying ASU’s rapidly growing research facilities. The CHP plant will ultimately generate 160,000 lb/hr of steam, 18.4 MW of electricity, and 24,000 tons of chilled water, making it perhaps the largest university central plant in the U.S.

The plant, which operates 24/7, re-quired a state-of-the-art control system that also is easy to use. So APS and Northwind specified a Matrix Total Con-trol unit from MTL Open System Tech-nologies (www.mtlmost.com) that puts all operator functions within a single display window. According to Ray Tena of ASU’s facilities department, “the system’s graphics and controls are easy to navi-gate and provide an effective and respon-sive operator interface.”

The control system comprises four re-dundant pairs of Matrix hybrid control-lers, eight remote nodes, each with a redundant pair of Ethernet bus interface and I/O modules, two double-tier opera-tor consoles, one remote interface termi-nal server, and one engineering station and industrial SQL server historian, all of

which communicate over a fault-tolerant Ethernet network (Figure 2). The system oversees the five chillers, the HRSG burner management system, and the two diesels and two turbines, and also operates the facility’s primary circuit breakers.

Interfaces to multiple intelligent devic-es (including Rotork smart valves, GE smart relays, and ABB variable-speed AC drives) were essential to providing the single-

window operator environment. More than 20 separate system interfaces enable more than 75 devices to talk to each other. Ad-ditionally, there are Ethernet interfaces to the programmable logic controllers of the combustion turbine and the HRSG duct burner management system.

Working with the control system, an in-dustrial applications server and a Factory-Suite Model A2 human-machine interface

1. Keeping the kids cool. The combined heat and power plant on the campus of Ari-zona State University includes five 2,000-ton chillers like this one. The plant’s chilled-water capacity is currently being expanded to 24,000 tons. Courtesy: APS Energy Services

2. Tightly integrated controls. Parts of the control system communicate with each other over a fault-tolerant Ethernet network. Courtesy: APS Energy Services

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POWER | January 200822

FOCUS ON O&M

from Wonderware (www.wonderware.com), a subsidiary of Invensys Systems Inc., pro-vide the single control window to all areas of the plant. The chillers and the combus-tion turbine are operated separately by the same operator from the facility’s only control room (Figure 3). Different-color backgrounds (blue for the chillers, green for the CT) distinguish the two systems.

Significantly, the control system en-ables all equipment of the CHP plant at ASU to be monitored and controlled re-motely by operators at another Northwind site via the company’s wide-area network. That feature allowed operators of the ASU plant to be trained onsite without disrupt-ing operations on campus while the system was operated from Northwind’s downtown Phoenix headquarters.

The Tempe plant’s control system also shares information with ASU’s energy in-formation system (EIS) through a Modbus interface. The EIS, which is maintained by APS Energy Services, provides detailed in-formation about individual buildings’ en-ergy usage. The university uses that data to develop building-specific invoices for electricity, gas, chilled and hot water, and steam usage.

—Contributed by Ed Antone (edmund.antone@apses.com), senior

project manager of APS Energy Services and Tim Schweitzer

(tim.schweitzer@mtlmost.com), project manager for the control system vendor.

SAFETY

Safety stuffers entertain as they informOrdinary Coffee spilled on the stairs turned them into a Deathtrap! Those stairs were … Deadly When Wet. Starring Slick DeMise. Rated P for Perilous.

Is that an advertisement for the lat-est direct-to-video horror movie? No, it’s text from the front of a “safety stuffer” published by the Mechanical Contractors Association (MCA) of Chicago and United Association Local Union (LU) 597. The small flyers accompany the weekly pay-checks of LU 597 workers employed by member contractors of MCA Chicago (Fig-ure 4). The one quoted above has its key message on the back: Please, clean up spills as soon as possible.

Twenty-six different stuffers are be-ing distributed, each conveying its safe-ty message in the form of a scary movie ad, complete with eerie illustrations. The safety stuffers are being paid for by the LU 597/MCA Joint Safety Committee.

“The safety stuffers remind workers to observe important safety measures on the job,” explained Stephen Lamb, execu-tive VP of MCA Chicago. Its mechanical contractors install and service heating, ventilating, air conditioning, and refrig-eration systems, as well as fire sprinklers

and plumbing and process piping. “We have the safest workforce in the industry, and we hope that stuffers help keep it that way.”

“The safety stuffers cover a wide vari-ety of vitally important worksite issues,” added James Buchanan, LU 597’s business manager. “There are stuffers that explain appropriate lifting techniques, proper lad-der usage, the need for personal protective equipment, lockout/tagout procedures, er-gonomics, fire safety, and more. There are even stuffers covering sexual harassment and workplace violence.”

Nehlsen Communications, a marketing and public relations firm, helped MCA Chi-cago develop the safety stuffers. “Safety is a huge issue to all of our construction clients,” said Nancy Nehlsen, president of the agency. “We have to find ways to get workers’ attention and make them constantly aware of hazards on the job. Today’s younger workers are used to the Internet and high-energy video games, so they like their information quick and en-

3. Screening room. Color-coded back-grounds differentiate the controls of the chill-ers and the combustion turbine. Courtesy: APS Energy Services

4. Always think safety. Chicago contracting unions have developed a series of unique “safety stuffers” that are distributed in weekly paycheck envelopes to remind members about the importance of safety. Source: Nehlsen Communications

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POWER | January 200824

FOCUS ON O&M

gaging. If you can’t excite their interest, you’ve lost them. So for maximum impact, we made each safety stuffer eye-catching and entertaining, with little text.”

“The safety stuffers are just one of many educational tools used by MCA Chi-cago and Local Union 597 to increase safety awareness,” Buchanan emphasized. “For example, we also hold Toolbox Talks at worksites. At the start of each workday, workers gather so the foreman can share the day’s prepared safety advice. Because everyone hears the talks, everyone ends up on the same page, safety-wise. Most talks remind them to work together and watch out for each other.”

MCA holds numerous safety classes in its own Construction Education Institute, a learning facility with course offerings for all levels in the mechanical construc-tion industry. Lamb said, “We now offer classes in CPR and first aid, automated external defibrillator training, electric arc safety, as well as OSHA’s 10-hour and 30-hour safety courses, and we add new courses constantly.”

Combined, these educational tools in-still in MCA Chicago’s member contractors and their LU 597 workforce a high level of safety awareness. Considering the high costs that accident-related injuries and lost work time can incur—including lost productivity, medical bills, administrative expenses, workers’ compensation fees, higher insurance premiums, the expenses of training replacements, and overtime for uninjured workers—it’s clear that any step to improve worker safety is worth the time and effort.—For more information on MCA Chicago,

visit www.mca.org. For more information on UA Local Union 597, visit www.pf597.org. For more information on attention-getting safety stuffers, contact

Mark McLaughlin (mark@ncpr.com), a public relations specialist for

Nehlsen Communications.

TRANSPORTATION

Doubling up for a heavy loadLast summer, Barnhart Crane & Rigging was hired to receive one generator and one tur-bine from a railroad, haul them more than 8 miles to a power plant rising near Emporia, Kansas (Figure 5), and then set them on their foundation. As part of the contract, the company also was supposed to install three transformers that it had hauled to the site earlier and had placed on stands and beams for temporary storage.

The major delivery challenge was a

bridge crossing. Fearing a collapse, the bridge’s engineer would not allow the generator and turbine to cross on a sin-gle-wide Goldhofer. He insisted that Barn-hart spread the load.

The solution was to begin the haul us-ing a single-wide Goldhofer. Then, as the bridge was approached, another Goldhofer

was brought alongside. The crew then slid the generator over to the middle of the now double-wide trailer (Figure 6). Once the bridge was crossed, the operation was reversed and the journey continued in a single-wide configuration. ■

—Contributed by Barnhart Crane & Rigging (www.barnhartcrane.com)

5. Close quarters. Barnhart used a 14-line Goldhofer electronically steered trailer to ma-neuver a new transformer into place at this combined-cycle plant being built in Kansas. Cour-tesy: Barnhart Crane & Rigging

6. Double-wide load. Bridge load limits required Barnhart to double up single-wide trail-ers. Courtesy: Barnhart Crane & Rigging

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www.powermag.com POWER | January 200826

LEGAL AND REGULATORY

One-size RPS does not fit allBy Roger Kranenburg, Edison Electric Institute

Roger Kranenburg

The U.S. Congress continues to debate proposals that would mandate that a set amount of the nation’s electricity come from renewable energy sources such as wind, the sun, or

biomass. These discussions about adopting a nationwide renew-able portfolio standard (RPS) raise significant concerns for power providers and customers alike.

Backers of a one-size-fits-all federal RPS believe it to be an es-sential component of a broad national energy strategy to address global climate change, improve air quality, and lower electricity price volatility. But in reality, a national RPS could disrupt exist-ing state renewable energy programs and put added pressure on electricity prices and reliability.

Impact on state programsStates are moving forward with their own programs to promote renewable energy sources. As of September 2007, 24 states and the District of Columbia had established an RPS. Four other states had nonbinding goals for adopting renewables, and 48 states now support programs that offer consumers incentives, grants, loans, or rebates to use renewable energy resources.

Each state’s RPS plan includes carefully considered timetables and targets based upon its own unique circumstances and avail-able energy sources. A federal RPS that imposes different targets and timetables could undercut or preempt those efforts. This would create uncertainty and drive up the cost of meeting renew-able mandates even further for electricity suppliers and consum-ers in those states.

Even among states that have an RPS, all have chosen to add energy sources unique to their areas, such as geothermal power, which are not included in the broad-sweeping federal RPS propos-als. Many state programs also include technologies such as fuel cells, as well as alternative means of compliance such as energy-ef-ficiency programs, which are not recognized in the federal plans.

Higher power costsFinally, not all regions of the country have abundant renewable energy sources that they can turn to for generating electricity. The cost for states in these regions to comply with a federal RPS could be high, because many of the retail electric suppliers in these areas will not be able to meet an RPS requirement through their own generation. They will be required to purchase higher-

cost renewable energy from other suppliers or purchase renew-able energy credits.

Thus a nationwide RPS mandate will mean a massive wealth transfer from electric consumers in states with little or no renew-able resources to the federal government or states where renew-ables happen to be more abundant.

A federal RPS would also mean higher costs due to the need to build high-voltage electric transmission lines. Renewable energy facilities, especially wind farms, are usually located in remote areas. To deliver their electricity to the populated areas where it is needed, transmission lines would need to be built. To do so will cost approximately $1 million to $3 million per mile.

Most renewable energy sources are intermittent, meaning they do not generate power all the time. Consequently, conventional power plants (most likely fueled by natural gas) need to be built to support them, which accounts for costs in addition to the cost of building the renewable energy facilities.

A better solutionThere are better ways to expand the use of renewables. Federal tax credits and increased funding for research and development are key. A long-term extension of the Production Tax Credit (PTC) could be the single most effective thing Congress could do to promote renewables.

Unlike the leading RPS proposals, the PTC is a proven means of actually getting renewable generation built and brought on-line. The current PTC is due to expire on December 31, 2008. In the past, the short-term, start-and-stop nature of the tax credit has dissuaded utilities, developers, manufacturers, and investors from maximizing the potential of renewable technologies and resources, where they are available. Extending the credit for at least five years will give the private sector the stability necessary to plan and finance renewable energy projects.

The nation’s electric utility companies support the develop-ment and greater use of renewable energy sources. Renewables, along with the full range of other climate-friendly technologies—including nuclear, energy efficiency, clean coal, carbon capture and storage, and plug-in electric hybrids—must be a part of the industry’s long-term approach to meeting the country’s steadily growing demand for electricity.

But renewables must be encouraged where they make eco-nomic sense. For this reason, a federal mandate that forces all states to generate an arbitrary amount of electricity from them, regardless of states’ individual resources, is bad for electricity customers and providers alike.

To learn more about the electric utility industry’s efforts to provide a reliable, affordable, and environmentally sensitive elec-tricity supply, please visit www.getenergyactive.org. ■—Roger Kranenburg (rkranenburg@eei.org) is director, business

development for the Edison Electric Institute (www.eei.org).

A long-term extension of the PTC could be the single most effective thing Congress could do to promote renewables.

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www.powermag.com POWER | January 200828

2008 INDUSTRY FORECAST

Regulatory risks paralyzing power industry while demand growsIn our second annual report on the state and future of the U.S. power genera-

tion industry, we combine the considerable experience of POWER’s edito-rial staff with the market savvy of Industrial Info Resources Inc. (see next story) to preview the industry’s direction in 2008. We anticipate that the specter of carbon control legislation will hobble coal and make renew-ables the hot ticket while nukes continue to inch forward in a generation market that is basically treading water.

By Kennedy Maize and Dr. Robert Peltier, PE

Predicting the U.S. power industry’s 2008 performance requires under-standing how utilities and other plant

developers respond to risk and uncertainty. Three years ago, mercury controls had the undivided attention of every coal plant op-erator. Today, the imminent arrival of carbon controls has caused a tectonic shift in the in-dustry. In years past, builders of new power plants focused on getting grandfathered out of new regulations. Today, developers are canceling plants before the climate change debate in Congress has ended, already as-suming the results will be bad for them.

Even the mere anticipation of carbon con-trols, and the sea change they will bring to the U.S. economy, has created strange bed-fellows and stranger enemies. Environmental groups are now embracing nuclear power be-cause they perceive it to be the lesser of two evils—after coal. Proposed carbon cap-and-trade regulations have executives of nuclear and wind power utilities vilifying their coun-terparts at coal-based utilities, who are asking for “need” allowances to ease the transition.

Thirty years ago, America’s major utilities faced common challenges arm-in-arm. That time has passed.

PURPA’s legacyFor example, 30 years ago utilities uniformly opposed passage of the Public Utility Regula-tory Policies Act (PURPA) as part of the Na-tional Energy Act. The Iranian revolution of 1978 began a period during which world oil prices doubled and some industry wags pre-dicted $100/bbl oil. PURPA forced utilities to diversify their generation resources and to purchase power from privately owned “quali-fied facilities.” The transition was difficult for industrial plant owners and utilities alike for several years, but market forces prevailed. Today, non-utility generation provides 35%

of America’s supply, and more than 44 GW of nuclear capacity is owned by independent power producers (IPPs).

PURPA also was instrumental in creat-ing the U.S. renewable generation market. For example, PURPA-inspired revisions to interconnection rules, long-term power purchase agreements, and tax credits made early solar thermal projects economic in the 1980s. Some credit PURPA with open-ing the door for 12,000 MW of nonhydro renewable capacity.

As the IPP market matured, natural gas–fired combined-cycle projects became the rage for their high efficiency, ease of permit-ting, small footprint, and short construction time. Gas-fired plants generating over 150 GW were built by 2006, when skyrocketing gas prices demoted so many plants designed for baseload operation to peaking service. Some were even mothballed.

Which way forward?PURPA was no longer needed once the U.S. generation market had become more mar-ket-driven and interdependent. Its death was sealed by the Energy Policy Act of 2005 (EPAct), but PURPA’s raison d’être remains: to promote the use of renewable energy, eliminate monopolistic market practices, and improve America’s overall energy efficiency.

Although we all approve of those objec-tives, the path forward remains uncertain. At no time in U.S. history have the options for generating power been so plentiful and the opinions of what is environmentally ac-ceptable so divergent. Never have regula-tors and utility executives disapproved new plants based on expected legislation, rather than laws on the books. Financial uncertain-ty slowed new projects after the gas bubble burst in 2001. Future projects now must deal with regulatory uncertainty and other threats

(see “Top 10 strategic business risks facing U.S. power generators”) just as reserve mar-

Top 10 strategic busi-ness risks facing U.S. power generatorsErnest & Young (E&Y) examined the

principal risk factors facing the U.S.

power generation industry and oth-

ers worldwide in the recently released

Strategic Business Risk 2008—the Top 10 Risks for Business. According to E&Y,

those top 10 risks, in descending order

of importance, are:

1. Regulatory and compliance risk

2. Global financial shocks

3. Aging consumers and workforce

4. The inability to capitalize on

emerging markets

5. Industry consolidation/transition

6. Energy shocks

7. Execution of strategic transactions

8. Cost inflation

9. Radical greening

10. Consumer demand shifts

The report also highlights the five

fastest-rising threats that could have a

significant impact over the next three to

five years (the war for talent, pandemic,

private equity’s rise, an inability to inno-

vate, and the threat of a China setback).

The complete report can be downloaded

from www.ey.com/global/assets.nsf

/international/ey_strategic_business

_risk_2008/$file/ey_strategic_bus_risk

_2008.pdf.

January 2008 | POWER 29

2008 INDUSTRY FORECAST

gins in some regions are declining to worri-some levels.

Uncertain prospects for “acceptable” gen-eration haven’t reduced America’s seemingly insatiable appetite for all things electric. Two months ago, the Department of Energy’s (DOE’s) Energy Information Administra-tion (EIA) predicted that consumption would grow 2.1% in 2007 but slow to a 0.5% in-crease in 2008 (Figure 1) as the effects of energy efficiency and other demand-side reduction programs kick in (see “Utilities to invest more in energy efficiency”). How-ever, demand continues to rise at double-digit rates in several regions that saw record peaks last summer. Although residential electric-ity prices are expected to stabilize at a 2% growth rate in 2008 after a two-year spurt (Figure 2), look for significant increases in subsequent years due to more use of costlier, cleaner fuels.

Nuclear projects inch forwardWill 2008 see the kickoff of the much-an-ticipated U.S. nuclear power revival? The Nuclear Regulatory Commission (NRC) thinks so. According to the Associated Press, the agency has hired 400 new employees to handle what it believes could be a deluge this year of applications for combined construc-tion and operating licenses (COLs) for new reactors. So many more paper-pushers will be needed because the COL process is new and has yet to have its efficacy and efficiency tested.

Bill Borchardt, head of the NRC’s new Of-fice of New Reactors, told the wire service that the regulator expects to receive 29 COL applications over the next three years. “We

1. Demand growth often down, but never out. America’s electricity consump-tion continues its slow rise. Source: U.S. Energy Information Administration

2. Moderate price hikes. Residential electric bills are expected to be 2% higher this year than they were last year. Further out, they will certainly rise much faster if mandatory carbon caps force power producers to use costlier, greener fuels. Source: U.S. Energy Information Administration

Cons

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ay)

13

12

11

10

9

8

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th (c

hang

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m p

rior y

ear)

4%

3%

2%

1%

0%

–1%

–2%1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008

2.6%1.8%

3.7%

1.7%

2.8%

2.1%

3.0%

0.5%0.1%

1.2%

2.1%

0.8%

–0.7%

Forecast

Mon

thly

ave

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ele

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ity p

rice

(cen

ts p

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13

12

11

10

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10%

8%

6%

4%

2%

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–2%

–4%1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008

0.9% 0.9%2.0%

5.6%

2.2%

10.1%

2.6%

4.2%3.2%

–1.6%–1.2%–2.0%

–0.5%

Forecast

Utilities to invest more in energy efficiencyEight regulated utilities serving 22 states have committed to

spend 50% more on their energy-efficiency initiatives and to

form a new institute to support efficiency endeavors. Consoli-

dated Edison Co. of New York, Duke Energy, Edison International,

Great Plains Energy, Pepco Holdings, PNM Resources, Sierra Pa-

cific Resources, and Xcel Energy say they will seek the regulatory

reforms and approvals needed to increase their collective annual

investments in energy efficiency to $1.5 billion within a decade.

It is hoped that the spending will not only reduce U.S. CO2 emis-

sions by about 30 million tons but also avoid the need to build

fifty 500-MW peaking power plants.

The eight power companies also promised to fund a national

institute for electric efficiency that would develop regulatory

models and convene conferences on efficiency that other utilities,

both foreign and domestic, would attend. The institute would be

overseen by the Edison Electric Institute, the industry organiza-

tion of U.S. investor-owned electric utilities. This commitment

would be part of the Clinton Climate Initiative.

One reason utilities are promoting energy efficiency is that

many states are setting regulatory standards and targets for it.

According to a report issued by the American Council for an En-

ergy Efficient Economy (ACEEE) in mid-September 2007, 15 states

had Energy Efficiency Resource Standards (EERS) in place, com-

pared with only five states two years earlier. The report estimates

that existing standards could reduce annual national electricity

demand by more than 1% by 2013.

The most aggressive targets in place are those of Vermont, which

reduced its electricity use by more than 5% between 2000 and 2006.

The Green Mountain State’s 2007–2008 target is a further reduction

of 3.5%. An even more aggressive goal is being developed in New

York State, where reform-minded first-time Governor Eliot Spitzer

would like 15% less consumption by 2015. The state’s Public Service

Commission is now exorcising the devil in the details.

The six-page ACEEE report is available at http://aceee.org

/energy/state/utpolicy.htm. The site also includes a link to a two-

page summary of the EERS policies of the 15 states.

POWER | January 200830

2008 INDUSTRY FORECAST

have never had to do this many reviews at one time in parallel,” he said. The AP story said Borchardt’s office “is nearly as large as the NRC unit overseeing the country’s existing 104 commercial reactor fleet.”

The NRC decided it would need to hire an army of application reviewers after re-ceiving numerous expressions of interest in building new reactors. EPAct contains a host of goodies for new nukes, including protec-tions against cost overruns, a 1.8 cents/kWh production tax credit (previously limited to renewables), and federal loan guarantees for up to 80% of the cost of a new plant. By the way, the loan guarantees apply to vir-tually every type of generation under the sun, including clean coal plants, factories building fuel-efficient vehicles, cellulosic ethanol plants (including the country’s first commercial plant in Georgia, developed by Range Fuels with a total DOE investment of $76 million), and the full spectrum of re-newable energy technologies.

But we’ve been here before—recently. Many in the U.S. nuclear industry were tout-ing 2007 (technically, the start of Fiscal Year 2008, which began October 1) as the start of their industry’s renaissance. It didn’t quite happen. As this story was being researched, in early December, the NRC had received three COL applications and was expecting seven more to be filed by the end of FY 2008 (Figure 3, p. 32).

How many new reactors?At the ELECTRIC POWER Conference & Exhibition in Chicago last spring, the mod-erator of one of the nuclear sessions, Dennis Demoss, of the contractor Sargent & Lundy, asked each of the panelists representing re-actor vendors to predict how many COL applications would be under review by the NRC when the trade show opens its doors in Baltimore in May 2008. The forecasts ranged from eight to none.

The prediction of “none” came from savvy Tom O’Neill of General Electric. Is realism trumping marketing hype?

In September 2007, NRG Energy Inc. (notably, not a nuclear utility) filed a COL for two new units at the existing South Tex-as Project. The application specified use of GE’s ABWR (advanced boiling water reac-tor), a design that has already earned NRC approval. A month later, Tennessee Valley Authority applied for a two-unit COL to build two Westinghouse AP1000 reactors at its Bellefonte site in Alabama, where 14 years of construction left two Babcock & Wilcox reactors unfinished and deemed unneeded by a 1988 prediction of lower-than-expected de-mand growth (see POWER, December 2007, p. 6). Then, in November last year, Dominion applied for a COL for a 1,520-MW General Electric-Hitachi ESBWR (the ES stands for “economic simplified”) to join two units at its North Anna, Va., site.

Could 2008 be another bust for the nukes?

One wise veteran of the nuclear industry pre-dicts that most of the action in Washington and in the nuclear marketplace this year will involve applications for license extensions for existing plants, rather than for COLs for new nukes.

Entergy Corp., an aggressive supporter of new nukes, had been widely rumored to be readying a COL application for 2007. It didn’t apply. According to a well-placed source, the company will sit out 2008 as well. Recently, news surfaced in the trade press of a dispute between Entergy and GE over the choice of the ABWR for a future plant. That chatter may just be the cover for a strategic Entergy decision to put its new nuclear plans on hold.

Nor is the number of COL applications a reliable measure of the nuclear rebound. Though COL applications take millions of dollars to prepare, that tiny ante only gets you a seat at the nuclear regulatory poker table. The big expenditures are still to come, and companies that have submitted COLs may change their mind without much financial penalty.

Nuke market FUDThe market for new nukes in 2008 is beset by the tactic IBM marketers used in the compa-ny’s heyday to bewilder competitors: FUD. That stands for “fear, uncertainty, and doubt.” There’s a one-word explanation for the FUD in the nuclear plant market: politics.

Nuclear is the most intensely political of generation technologies (although coal is making a strong bid for the lead), and the pol-itics tend to be partisan. Democrats generally are averse to the atom, while Republicans as a whole are fond of fission.

This year we’ll watch the quadrennial po-litical Super Bowl as the nation elects a presi-dent and vice president, all 435 members of the House of Representatives, and one-third of the U.S. Senate. At this early stage of the game, most political pundits are predicting that a year from now, the Democratic Party will have power it hasn’t had since 1993: one of its own in the White House and control of both the Senate and the House.

That’s not a given; plenty can happen be-tween now and this November. But prospects don’t look good for the GOP, and that means they don’t look good for new nukes. The U.S. nuclear industry decided—even before the 2006 elections, which produced a Democrat-ic majority in both houses of Congress—to bet the radioactive ranch on the GOP. The nu-clear industry lobby was, to use a waterski-ing and snowboarding term, “goofy-footed” by the Democratic tsunami—caught with its right foot in the forward binding.

Eight years of Republican control of the

Clinton, Obama agree: Death penalty for Yucca MountainThe two front-runners for the Democrat-

ic presidential nomination have urged

abandonment of the Yucca Mountain

nuclear waste repository. They say that

Congress and the Department of Energy

should develop an alternative national

strategy for storing high-level nuclear

waste, given the absence of solutions

to safety and technical problems that

have arisen at the Nevada site.

By proposing to shut down Yucca

Mountain before it opens, Senators Hill-

ary Rodham Clinton (D-N.Y.) and Barack

Obama (D-Ill.) may be eyeing the five

electoral votes allotted to Nevada. They

certainly have no need to persuade its

Democratic U.S. senator, Harry Reid, the

majority leader and one of Capitol Hill’s

staunchest Yucca opponents. Nevada’s

residents overwhelming oppose the re-

pository, which is 90 miles northwest of

Las Vegas. Polls say its fate will be a

major issue for Nevadans in the Novem-

ber national elections.

Whatever their intentions, Clinton’s

and Obama’s opposition to Yucca—now

clearer than ever—indicates that the

project’s death warrant may be signed

if a Democrat wins the White House

next year.

“Yucca Mountain is not a safe place

to store spent fuel from our nation’s

nuclear reactors,” said Clinton. Instead,

she suggested U.S. policymakers should

“start over and assemble our best minds

to identify alternatives.”

Obama, who pointed out that his

home state of Illinois is home to more

nuclear reactors (11) than any other

state, said, “I believe that it is no lon-

ger a sustainable federal policy for Yucca

Mountain to be considered as a perma-

nent repository.” As alternatives, Obama

suggested Congress and the DOE could

try to find another state willing to serve

as a permanent national repository, or

create regional storage repositories.

“Decision making is easy when you have the right information at the right time.”

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POWER | January 200832

2008 INDUSTRY FORECAST

3. Get in line. This estimated schedule by fiscal year shows new reactor licencing applications by site and technology. Many applications have been submitted, but there’s been little real progress so far. Source: U.S. Nuclear Regulatory Commission

January 2008 | POWER 33

2008 INDUSTRY FORECAST

White House, and 12 of Congress, haven’t delivered for nuclear power. As one nuclear lobbyist, speaking anonymously for fear of losing his job, told POWER, “We’ve had the most pro-nuclear administration in 20 years. During its reign, not a spade of dirt has turned on a new plant. The schedule for the nuclear waste repository at Yucca Mountain has slipped another 12 years. The Depart-ment of Energy has been unable to turn the promises of the 2005 Energy Policy Act into realities. It’s a failure of monumental propor-tions.” Put Yucca Mountain in that same cat-egory (see “Clinton, Obama agree: Death to Yucca Mountain” p. 30).

When Republican President Gerald R. Ford faced a different kind of energy crisis in mid-1970s (the result of the Arab oil embargo), he and the Democratic Congress worked to-gether to serve up an attractive plate of good-ies for new nukes. When Democrat Jimmy Carter took office in 1977, the menu instantly changed to gall and boronated wormwood. According to the anonymous lobbyist, the U.S. nuclear industry began melting down in 1976 with Carter’s election, not in 1979 with Three Mile Island. “I was there,” he said. “As soon as Carter made his selections for the NRC, the industry crashed.”

Nukes face stiff political windA new Democratic administration isn’t likely to push licensing of new nuclear plants. In-deed, the nuclear industry’s worst regulatory nightmare is very much a political possibil-ity: NRC Commissioner Gregory Jaczko be-coming the agency’s chairman. Jaczko, a very bright and sharp-elbowed political player, is considered “Harry Reid’s guy” at the NRC.

A PhD physicist, Jaczko came to Congress as a science fellow working for Rep. Ed Mar-key (D-Mass.), one of the most anti-nuclear members of Congress over the past 30 years. Jaczko decided he liked Washington and be-came Reid’s chief advisor on nuclear waste is-sues. Reid has vowed to kill Yucca Mountain, and he may be able to keep his promise come January 2009. Jaczko professes, no doubt honestly, that he is not anti-nuclear power.

But Jaczko has every reason to be anti–nu-clear industry. The Nuclear Energy Institute tried, and failed, to block his initial appoint-ment to the NRC when he won a recess ap-pointment—as did Republican Peter Lyons, a former advisor to former Senate Energy and Natural Resources Committee Chairman Pete Domenici (R-N.M.). That was a deal the White House and Reid negotiated, over the objections of the nuclear lobby.

Then the nuke reps tried to derail Jaczko’s nomination to fill a full term last year. They failed. Recently, the nuclear lobby tried to abort a second term for Jaczko. They were

unsuccessful. Said our lobbyist, “We’ve tried to screw this guy three different times and failed. How understanding and helpful is he going to be when he runs the NRC?” There’s little doubt that if the Democrats reclaim the White House, Jaczko, the only Democrat on the commission, will become its chairman.

The industry’s political support in Con-gress has diminished substantially recently. Domenici, the nuke lobby’s leader in the Sen-ate, is a spent force. He’s ill and sometimes unfocused, and he’s announced he’s stepping down at the end of 2008. The second-most-ardent nuke supporter in the Senate is Idaho Republican Larry Craig. His political career is apparently in the toilet. In recent years, the number-three supporter was Wyoming Republican Sen. Craig Thomas, a buddy of vice president Dick Cheney. Thomas died last year. There are no important nuclear stal-warts on the Democratic side of the House or Senate.

The politics of nuclear power will mani-fest themselves directly in financial markets. It won’t matter how badly a utility wants to build new nuclear capacity if it can’t convince lenders their investment is a safe one. No one is going to risk $5 billion or more on a new plant without assurance of at least capital re-covery plus a return. For most generators, it’s a bet-the-company gamble.

So while the politics of new nukes look bad, their short-term financing outlook isn’t very promising, either. An October study of the U.S. industry by Moody’s Financial Ser-vices concluded that “there can be no assur-ances that tomorrow’s regulatory, political or fuel environment will be as supportive to nu-clear power as they are currently.” The NRC’s 42-month COL process, Moody’s noted, “remains untested.” Opponents of nukes are likely to litigate NRC decisions, adding time, money, and doubt to the process.

Most ominously, Moody’s suggests that the current estimate of the average cost to build a reactor and start it up by 2015—around $3,500/kW of capacity—is pie in the sky. A more realistic all-in cost for a new re-actor, says the bond rating agency, is in the $5,000 to $6,000/kW range. That’s consid-erably more than conservative estimates for new integrated gasification combined-cycle (IGCC) coal plants. American Electric Power (AEP) estimates its planned 600-MW IGCC plant will cost $3,500/kW.

Coal’s progress slowed If nuclear has another losing hand in 2008, will that make coal a winner? Maybe, maybe not. It’s another case of the political correct-ness of generation. Coal—and its link to CO2 emissions—has become at least as un-PC as nuclear power.

Last year opened with good prospects for coal for three reasons: its superior econom-ics, more-efficient ways to burn it (such as supercritical boilers), and slowly improving prospects for CO2-capturing IGCC plants. TXU had an ambitious plan to build 11 con-ventional coal-fired plants to serve the boom-ing Electric Reliability Council of Texas wholesale market (the same market NRG is targeting with its nukes). Tampa Electric, which already operates a DOE-subsidized 260-MW IGCC unit in Florida, was saying it would build another of 630 MW valued at $2 billion by 2013.

Other coal-fired projects popped up con-sistently during the early months of 2007. Then the pace slowed in response to stepped-up environmental opposition, concerns about future greenhouse gas regulation, and spotty support by state regulators.

By the end of the year, many of the early ambitions for coal had faded. As part of a leveraged buyout orchestrated by Kohlberg Kravis Roberts & Co. to take the company private, TXU agreed to scrap all but three of its planned coal plants. Local activists opposed to the utility’s coal-based strategy persuaded KKR that green protests and liti-gation would delay or derail the buyout un-less the utility scaled back its plan.

The tactics used by environmentalists against coal projects around the country were clever. If a utility or IPP proposed a conven-tional coal-fired plant, they argued to local regulators that it shouldn’t be approved unless the developer promised to make it capable of capturing carbon. If the developer agreed, the plant’s opponents would demand that the project abandon pulverized coal in favor of the cleaner but untested IGCC technology.

IGCC reality strikesThen, market realities took hold. A refinery-like process, IGCC is inherently much more expensive than conventional combustion of coal or gas. What’s more, the economics of capturing and storing carbon are as unknown as the technologies are unproven; no current-ly operating plant can do both.

Nor does anyone really know what to do with the CO2. The multisyllabic buzzword is “sequestration,” meaning “put it somewhere out of sight.” Where? There’s no shortage of suggestions: in salt caverns, in old coal mines, into oil and gas reservoirs to boost their output, under the seabed, under your mattress. How about shooting the CO2 into outer space? If the gas isn’t permanently stored, it will eventually find its way back into the atmosphere.

Veterans of prior decades’ energy debates are reminded of the long, fruitless discus-sion about what to do with spent nuclear

POWER | January 200834

2008 INDUSTRY FORECAST

fuel, aka high-level nuclear waste. Bury it in salt caverns? Dig a hole in Nevada? Bury it in seabeds? Shoot it into space? Yucca Mountain notwithstanding, there’s no real answer yet, other than to keep the waste at plant sites.

The question of CO2 disposal, at least in terms of volume and weight, is much bigger than that of what to do with spent nuclear fuel. There’s a heck of a lot more CO2 com-ing from fossil-fueled plants than fatigued fuel from nukes. The nuke waste is solid, making it easier to handle than gaseous CO2.

Like nuclear safety and spent-fuel storage, coal’s CO2 emissions have become intensely political, although not particularly parti-san. Democrats (New York Governor Eliot Spitzer), Republicans (California Gov. Ar-nold Schwarzenegger, Florida Gov. Charlie Christ, Arizona Sen. John McCain), and in-dependents (Sen. Joe Lieberman of Connect-icut) alike are telling gencos they can’t use coal if they can’t hide the CO2 somewhere.

In California, the state legislature, with the governor’s backing, passed a law that not only continues a decades-long ban on coal burning in the Golden State but also puts an end to utilities (including municipals) buying power generated by coal in other states, as they have done for generations. In Florida, Christ’s contempt for coal led Tampa Electric to scuttle its new IGCC project.

The New York Times reported in October that in the Rocky Mountain West, where en-ergy development has long been a favored land use, “An increasingly vocal, potent and widespread anti-coal movement is develop-ing” as ranchers and farmers join with tra-ditional environmentalists to resist coal-fired projects. Also joining the no-coal coalition are ski resort operators, retired homeowners, and religious groups, the Times reported.

The Times article quoted Rick Sergel, CEO of the North American Electric Reliability Corp., the nation’s reliability watchdog. He said, “It’s clear new coal-fired generation is running into roadblocks. I don’t believe we can allow coal-fired generation to become an endangered species. We simply must use all the resources we have.”

That’s not how environmental groups see the constant battle to ensure that supply matches demand. According to the Sierra Club’s Bruce Niles, who runs the group’s national campaign again coal, his group and others have worked together to file 29 ad-ministrative actions and lawsuits against pro-posed coal plants.

Not all have succeeded, of course. Pea-body Energy’s Prairie State Energy Campus, a proposed 1,500-MW mine-mouth project in southern Illinois, has survived a withering

legal attack and now looks like it will indeed get built.

Coal projects sidelinedA DOE report (www.netl.doe.gov/coal/refshelf/ncp.pdf) released late last year con-tained mostly bad news for coal generation. Of 12,000 MW of new coal-fired capacity announced in 2002 for expected commission-ing in 2005, only 329 MW actually got built. According to the report, during an average year between 1997 and 2006, only 293 MW of new coal-fired generation came on-line.

Still, the DOE says it believes a fair—but unspecified—share of the 23,000 MW of the coal plants it considers “progressing” (either permitted, near groundbreaking, or under construction) may get built. Said the report, somewhat ambiguously, “Progressing plants have a higher likelihood of advancing toward commercial operation, however there is still a degree of uncertainty in these projects.”

Last year’s trade press was full of reports of such coal projects getting delayed and cancelled:

■ In South Dakota, two of the seven ma-jor partners in the 630-MW Big Stone II project, representing 28% of its owner-ship, have pulled out, while a major muni, Rochester (Minn.) Public Utilities, has said it will not be an equity partner. Roch-ester may buy some of the plant’s output.

■ In 2004, Duke Energy proposed build-ing two 800-MW supercritical coal units to help meet growing regional demand. Last February, the North Carolina Utili-ties Commission (NCUC), not known as a patsy for green groups, approved only one, citing excessive costs. Duke is con-sidering abandoning the entire project, ac-cording to trade press reports.

■ In September, the Oklahoma Corpora-tion Commission rejected a coal project proposed by AEP and OGE Energy. The utilities had proposed capturing its CO2 and using it to enhance oil and gas recovery from the state’s elderly fields. The rejection caused Southern States Energy Board chief Kenneth Nemeth to note a “groundswell of movement away from fossil energy,” ac-cording to the Foster Electric Report.

■ In Florida, a month before Tampa Elec-tric pulled the plug on its $2 billion IGCC plant, the state public service commission gave a thumbs-down to a Florida Power & Light Co. plan for a coal-fired plant in Glades County. That led a municipal joint action agency in the Sunshine State to mothball plans for an 800-MW coal-fired plant in north Florida.

■ In November, Idaho Power shelved the portion of its integrated resource plan that

called for 250 MW of new coal capacity. The utility cited rising costs and uncer-tainty about greenhouse gas regulations as the reasons.

Perhaps most disturbing to developers of coal plants was an October rejection by the Kansas Department of Health and Environ-ment of an air permit for a $3.6 billion, two-unit, 1,400-MW plant proposed by Sunflower Electric Power, a rural electric generation and transmission cooperative. The sole reason for the rejection, said Roderick Bremby, head of the state agency, was CO2. He said it would be “irresponsible to ignore emerging infor-mation about the contribution of carbon di-oxide and other greenhouse gases to climate change and the potential harm to our environ-ment and health if we do nothing.”

The Kansas decision is ripe for litigation, according to experienced Washington energy lawyers. While the Supreme Court last year ruled that the U.S. Environmental Protection Agency has the authority to regulate CO2 emissions under the Clean Air Act, the EPA has not issued regulations. So, according to industry environmental lawyers, Kansas will have a hard time arguing that it has authority to regulate in the absence of an EPA regula-tory regime.

Nonetheless, the Kansas ruling troubles the generating industry, suggesting that the assault on coal will continue and the ferocity will increase. Washington energy consultant Roger Gale told the Baltimore Sun recently, “Coal is a tough sell, and clean coal is get-ting comparable to a nuclear plant” in capital costs.

The real growth in coal-fired generation in 2008 will take the form of plant upgrades and efficiency improvements to extend plant life and increase capacity factors.

If not coal, then what?

Gas-fired plants regain the advantageFor the past five years or so, the big story in U.S. power generation has been the re-treat from natural gas, which was the fuel of choice in the 1980s and 1990s. Gas, long in surplus (remember the “gas bubble?”) and featuring steady and declining prices, was the ideal generating fuel for the end of the 20th century. Generators could build low-capital-cost units and arbitrage the different market prices for gas and electricity—the “spark spread”—at will. So build they did, because the economics continued to favor gas.

With low plant upfront costs and short construction times, natural gas dominated. Though gas is costlier than coal on a $/Btu basis, the low heat rates of combined-cycle combustion turbine plants minimize the pre-

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2008 INDUSTRY FORECAST

mium as they operate. The emissions profile of gas plants looked good, particularly com-pared to coal. Through the ’90s, environ-mentalists gave gas a pass, seeing it as the transition fuel to a renewables future.

That changed around the end of 2001 (about the same time as the fall of the House of Enron). Gas inventories plummeted, in part due to the collective demand of all those new combined-cycle plants. Prices became volatile. Generators that had dashed to gas now fled from it. Scores of gas-fired projects announced late in the gas boom never made it off the drawing board.

Today, gas has regained some of its glit-ter. As crude oil prices surged above $90/bbl, the alleged linkage between the prices of oil and gas proved to be a myth. Gas prices have stabilized. They appear to have leveled off at around $7 per thousand cubic feet—well be-low the prices seen earlier this decade.

As a result, gencos are again considering natural gas plants their least-risky option, in light of gas plants’ low capital and construc-tion costs and the political incorrectness of the nuclear and coal alternatives. Randy Zwirn, CEO of Siemens Power Generation, told an industry meeting last year, “By de-fault, the only technology that’s going to be available is gas-fired generation.”

Although attention recently has focused on new nukes and cancelled coal, gas has been showing stealth strength. A recent EIA report noted that natural gas–fired genera-tion “showed the highest rate of growth from 2005 to 2006 of the traditional energy sourc-es,” accounting for 20% of all new genera-tion in 2006. Compared to 2005 figures, said the EIA, gas-fired generation in 2006 grew by 7.3%, while nuclear grew by 0.7% (due to upratings and better plant performance) and coal fell by 1.1%.

Increasing gas reserves fuel optimism Is enough gas available to supply new power plants as well as residential and industrial furnaces? Last October, the DOE’s Potential Gas Committee, a group of volunteer energy experts, issued a new estimate of recoverable domestic gas reserves that is 17% higher than one made in 2004. The committee said the U.S. has some 1,525 trillion cubic feet of re-coverable gas, compared to its 2004 estimate of 1,308 tcf.

That’s the largest increase since the com-mittee started estimating reserves in 1964, ac-cording to The Energy Daily (like POWER, an Access Intelligence publication). The com-mittee said new reserve estimates exceed the 36 tcf of gas that U.S. producers extracted be-tween 2004 and 2006.

Meanwhile, the 2007–2008 winter as-

sessment by the Federal Energy Regulatory Commission (FERC) found, “For the second year, the prospects for natural gas markets as we head into this winter are very good.” FERC staffers said gas storage is “robust,” winter temperatures are forecast to be mild, new pipelines and liquefied natural gas (LNG) terminals are coming on-line, and gas in storage should exceed record levels as winter kicks in.

The FERC staff report concluded, “Basi-cally, we expect to see full storage this year. Effectively full storage goes a long way to-ward protecting the country from the disrup-tions and price spikes associated with tight supply/demand balances in the winter.” If the forecasts for a warmer-than-normal win-ter are accurate, said the report, “gas prices could remain stable or even see some down-ward pressure.”

Last November, the EIA reported that proved U.S. natural gas reserves grew by 3% in 2006 to 211 tcf. That’s the highest reserve level since 1976, the agency added. The driv-er of that growth was the use of new drilling techniques that have given explorers access to unconventional gas, such as the Barnett Shale in Texas. According to the EIA, addi-tions to gas reserves in 2006 replaced 136% of the gas produced that year. It was the eighth straight year that proved gas reserves have grown.

Concrete evidence that utilities are not shy-ing away from natural gas comes from Duke Energy, which last summer asked the NCUC to approve up to 1,600 MW of new combined-cycle gas-fired capacity after having its pro-posal to build the same amount of coal-fired capacity turned down. Florida utilities are also looking seriously at new gas units, likewise following rejection of coal-fired plants.

A most unusual gas-fired plant has been proposed by Basin Electric Power Coopera-tive, a large generation and transmission co-op based in Bismarck, N.D. In late October 2007, Basin said it would like to build and commission a 300-MW unit in the eastern part of the state by 2012. At the heart of Deer Creek Station would be a simple-cycle com-bustion turbine generator and a heat-recov-ery steam turbine generator. Both would run about 12 to 16 hours a day in intermediate service, following load on the systems of the distribution cooperatives that Basin supplies.

What’s unusual about that? Nothing. How-ever, Deer Creek would burn synthetic gas (syngas), rather than natural gas. The supply would come from Basin’s Dakota gasifica-tion project, which uses Lurgi technology to turn lignite into syngas that then can be transported by the Northern Border Pipeline. Developed in the 1980s, the Dakota project is America’s only large-scale converter of

coal to gas. The fact that it has never been replicated in the U.S. suggests that there are cheaper ways to go.

LNG lags behindEarly last year, there was buzz about lique-fied natural gas. By the beginning of 2008, it had quieted to a murmur. Ambitious LNG projects became stalled as a result of intense local opposition and stabilization of the con-ventional U.S. natural gas market.

According to FERC, five LNG receiving terminals with a total capacity of about 6 bil-lion cubic feet (bcf) per day operate in the U.S. today. The agency has approved another 21 projects but acknowledges that most of them will never be built.

For example, California Gov. Arnold Schwarzenegger in May last year rejected a plan for an $800 million LNG terminal off the Southern California coast proposed by an Anglo-Australian company. Earlier, the Cali-fornia Coastal Commission had unanimously rejected the project.

Nor does there appear to be a crying need for LNG in today’s market. A Reuters story last October noted that LNG imports to the U.S. were expected to continue a slide begun several months earlier, “as steady demand from the Far East and early buying from Eu-rope soak up more spot supplies.”

According to the Houston-based consul-tancy Waterborne Energy, U.S. LNG im-ports in September 2007 were about 45 bcf, or about half the 89 bcf imported in August 2007. The firm’s estimate for October was less than 45 bcf. Weather was partially re-sponsible, said Waterborne. While unseason-ably cool weather in the UK raised natural gas prices to about $9/mmBtu, a mild autumn in the U.S. Northeast saw gas prices drop to about $6/mmBtu at the Henry Hub market. The LNG flowed to the UK.

In their forecast of natural gas markets for 2007 and 2008, FERC staff portrayed LNG as a swing resource. According to FERC’s di-rector of gas market oversight, Steve Harvey, LNG acts as insurance. “Depending on in-ternational gas prices,” he said, “supply may or may not be available to U.S. markets.” So much for the LNG boom.

Renewables ahead by a noseWind power has been soaring for several years, driven by state mandates (renewable portfolio standards) and federal subsidies (the production tax credit). But the boom represents a start from a tiny base; wind power remains a miniscule contributor to the national electric supply. Considering its inherent dispatchability problems (wind is intermittent) and the need for backup genera-tion if the resource is to be a major contribu-

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POWER | January 200838

2008 INDUSTRY FORECAST

tor to total U.S. supply, wind’s future could be summed up as positive but limited.

In November, the American Wind Energy Association (AWEA) upped to 4,000 MW its earlier prediction that 3,000 MW of wind power would be added to U.S. grids in 2007. Either number would top the 2006 record of 2,454 MW. In its second-quarter report on the state of the generation niche, America’s biggest wind power promoter said 935 MW of capacity were commissioned during the quarter, bringing first-half 2007 capacity additions to 1,059 MW. In the third quarter alone, 1,251 MW of wind power were added, including 600 MW in Texas alone.

But there is a supply-chain cloud on wind energy’s horizon, according to AWEA. The news release announcing the Q2 report warned, “Wind power developers report that

turbine availability is a limiting factor—in other words, there is demand for even more wind energy but companies can’t build more projects because there aren’t enough manu-facturing facilities for turbines and turbine parts in the country because the U.S. govern-ment’s intermittent policy toward renewables has discouraged companies from investing in manufacturing facilities.”

If conventional economics holds, the short-fall in the supply of wind turbines will raise the cost of wind farm construction. However, unmet demand for ingredients common to all power projects—concrete, rebar, steel, labor, and other commodities—are bidding up their costs, too. It’s a sellers’ market, which further undermines the economics of wind power.

That highlights a policy problem for wind. Congress refuses to make a long-term com-

mitment to the 1.8 cents/kWh production tax credit for renewable energy plants. The view of many legislators is that the credit should be a short-term subsidy to help the industry reach commercial viability, as opposed to a permanent entitlement.

The wind industry sees the sop differently. Said Randall Swisher, AWEA executive di-rector, “What is critical at this juncture is for the U.S. government to put in place a full-val-ue, long-term extension of the production tax credit and a national renewable energy port-folio standard requiring that utilities gener-ate more electricity from renewable sources. These policies will give the clear, big-picture signal of support for renewable energy that this country urgently needs.”

Renewable resources technologies as a whole aren’t proliferating nearly as quickly as wind power. According to the EIA, wind generation grew from 3,684 MW in 2001 to 8,706 MW in 2005. But the entire category of renewable energy generation grew only from 95,096 MW in 2001 to 98,791 MW.

The vast majority of American renewable-fueled power production (using the EIA’s definition) comprises conventional hydro plants, the bane of most mainstream envi-ronmentalists. Hydro’s heyday here seems to have passed; no one is proposing new proj-ects and old ones are fading away. In 2001, big hydro generated 78,916 MW; in 2005, the figure was 77,541 MW.

Other renewable generation tech-nologies—photovoltaic arrays, biomass combustion, and geothermal energy extrac-tion—remain trivial and slow-growing. Na-tionwide, solar electric generation accounted for 392 MW in 2001 and 411 MW in 2005, and just a handful of larger projects are on the horizon. Biomass generation—from plants burning wood, wood waste, and municipal solid waste (including landfill gas)—made the slimmest of gains: from 9,708 MW in 2001 to 9,848 MW in 2005. There is little evidence to suggest that any of these proven renewable fuel technologies will grow sub-stantially in 2008. However, some of their less-conventional brethren are enjoying ma-jor development funding (see “Google this: ‘Clean and cheap power’ ”).

Your turnThere you have it—our thoughts about what to expect in 2008. We’ve given you the best information and data available, and we en-courage you to use them to form your own opinions about U.S. generation options. We haven’t been shy about telling you what we think, and we hope you’ll repay the favor. Send your comments to editor@powermag.com and we’ll publish the most interesting letters. ■

Google this: “Clean and cheap power” Renewable energy has attracted the big-

gest cyber-gorilla of all: Google, which

has announced a crash program to develop

1,000 MW of generation capacity capable

of producing electricity more cleanly and

cheaply than burning coal.

The search engine giant said it is al-

ready hiring engineers and energy experts

and plans to invest hundreds of millions

of dollars in renewable energy projects,

starting with innovative solar thermal

technology.

The company suggested it could lever-

age its experience building complex, elec-

tricity-hungry data centers to help clean

energy entrepreneurs speed the deploy-

ment of utility-scale, “green” power tech-

nologies. Sergey Brin, Google’s cofounder

and president of technology, put the com-

pany’s program in a broader context, say-

ing: “Cheap renewable energy is not only

critical for the environment, but also vital

for economic development in many places

where there is limited affordable energy

of any kind.”

Google’s self-admittedly “lofty” goal of

1,000 MW of deployed, cheaper-than-coal

clean energy sets a new mark for ambi-

tion. How audacious is it? The U.S. wind

industry, using a proven technology and

subsidized by taxpayers, installed just

4,000 MW last year.

Google said it already is working with

two small renewable energy start-ups in

California. Their work, while still in the

early stages of development, illustrates

the potential of next-generation green

power technologies to change the eco-

nomic equation.

One is eSolar Inc., based in Pasadena,

which says it has developed a utility-

scale solar thermal technology that can

economically heat water to drive a power-

generating turbine. The company’s modular

approach calls for deploying heliostats—

moving mirrors—to track the movement of

the sun and direct solar energy to receiving

towers that generate steam. The company

says each of its modules can generate 25

MW, with multiple modules providing op-

erational redundancy and size.

The other company is Makani Power

Inc., based in Alameda. Makani (the Ha-

waiian word for wind) says it is develop-

ing “high-altitude wind energy extraction

technologies.” Though the company’s Web

site provides few details, a fact sheet re-

leased by Google shows a large sail-like

structure that would presumably catch the

wind, which is much steadier worldwide

thousands of feet up than at the height of

even the tallest wind turbine towers.

The clean energy initiative will be led by

Google.org, the company’s philanthropic

arm. That no doubt comes as a relief to

Google shareholders, especially in light

of company officials’ remarks about their

investment criteria for the program. But

its name, RE<C (an equation stating that

renewable energy is cheaper than coal),

reflects Google’s geekiness and reinforces

its brand.

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www.powermag.com POWER | January 200840

2008 INDUSTRY FORECAST

Greater fuel diversity needed to meet growing U.S. electricity demandIndustrial Info Resources’ strengths are tracking capital projects and cost pro-

jections and providing intelligence about the power generation market, among others. IIR has used its large industry databases and numerous industry contacts to develop its outlook for 2008. Here’s what you should expect and plan for this year.

By Britt Burt and Shane Mullins, Industrial Info Resources

Continued economic growth in the U.S. over the next several years will inevi-tably drive growth in electricity con-

sumption (Figure 1). Meeting the projected 40% increase in national demand by 2030 that today’s double-digit annual growth rates will produce will require building a lot more power plants—some to replace the capacity of retired units (Tables 1 and 2).

Who will use that new power, and for what? Demand growth by the commercial sector and its services providers will outstrip that from the residential sector and industrial users. Increases in population and disposable income will whet the appetite for more prod-ucts and services, in turn increasing the sizes of residences and business floor space. More electricity will be needed to heat and cool those areas and to power appliances, comput-ers, and other electrical devices.

As electricity demand grows, so does the need to diversify fuel sources to ensure sup-ply reliability. Until 2001, the U.S. power in-dustry expected to rely heavily on natural gas to meet growing demand. During the 1990s, more than 300,000 MW of natural gas–fired capacity were built. Since then, natural disas-ters and international politics have shed light on the risks of relying too heavily on one fuel source. So while power project devel-opers still consider new gas-fired plants an option, they and utilities are also implement-ing strategies to build and better utilize coal-fired units, construct more renewable energy plants, and even develop a second wave of U.S. nuclear reactors to meet growing elec-tricity demand (Tables 3 and 4).

Coal: The king still gets no respectDespite the best efforts of environmentalists

and renewable-energy advocates, coal still fuels about 50% of U.S. electricity genera-tion, and its share may rise. A boom in coal plant construction is in full swing: 27 units totaling 12,000 MW, collectively worth more than $20 billion, are already past the ground-breaking phase. Those 12,000 MW represent 34% of all capacity currently being built in the U.S. Of the total, 1,174 MW are expected to come on-line this year, to be followed by 5,888 MW in 2009 and 4,700 MW in 2010.

The near-term units signify only the be-ginning of a longer-term expansion of U.S. coal-fired generation. In addition to the 27 units that have already poured concrete, an-other 243 units representing 74,000 MW and worth $120 billion are on the drawing boards of utilities and independent developers. Of that total, 26,000 MW are scheduled to break ground this year, with the rest following be-tween 2009 and 2011.

Utilities have proposed building 84 of the 243 longer-term units to increase their gen-erating capacity by 31,300 MW. They envi-sion building 44 units with a total capacity of 16,300 MW as greenfield plants. The other 40 units, representing 15,000 MW, would be additions to existing power stations.

In contrast, private energy producers have proposed 159 coal-fired generating units able to produce 42,700 MW. Of these, 120 units and 31,900 MW are planned to be part of greenfield plants while 39 units and 10,800 MW will be added to existing plants.

The vast majority of the projects in devel-opment will rely on conventional pulverized coal combustion. But an increasing number plan to use integrated gasification combined-cycle (IGCC) or circulating fluidized bed (CFB) boiler technology. Specifically, 40 IGCC plants totaling 23,000 MW, and 22 CFB units totaling 6,600 MW have been pro-posed nationwide.

New coal plants are being proposed not just to meet future demand but also to re-place coal plants scheduled for retirement.

1. Double digits across the board. New generation capacity is being developed that has planned commercial start-up dates between 2008 and 2012. Source: Industrial Info Resources

©2007 by Industrial Information Resources - Sugar Land, TX

54%

West Coast39,319 MW

38%

Rocky Mountains28,394 MW

4%4%

25% 5%

15% 55%

40%

6%

10%

30%

33%

12%

25%

4%

42%

16%

20%

56%44% 5%

34%

60%

40%

38%

5%

14%

47%

19%

Midwest26,432 MW

Great Lakes31,155 MW New England

9,726 MW

Mid-Atlantic28,348 MW

Northeast21,028 MW

Southeast25,582 MW

Southwest44,218 MW

18%

Coal 28% Nuclear 20% Renewable energy 33% Project locationsNatural gas 19%

50%

14%

18%

January 2008 | POWER 41

2008 INDUSTRY FORECAST

Table 1. Actual and planned U.S. power generation resource growth (1998–2008) by state. Source: Industrial Info Resources

Operational 1998

Added 1999–2007

Retired/mothballed since 1999

Currently operational

Actual growth since

Jan. 1, 1999

Operating fossil capacity

>40 years old

Generation under

construction

Announced commercial

start-up

in 2008a

23,207 276 10,018 57 266 14 32,549 304 9,341 28 6,408 38 621 32,358 357 401 56 110 57 2,546 325 188 -32 125 23 50 8 50 11

15,601 162 11,140 91 351 17 25,951 211 10,349 49 1,687 26 606 7 308 810,481 139 5,921 52 1,541 40 14,817 143 4,336 4 507 8 940 6 60 357,184 1,142 16,951 285 5,034 121 64,825 1,252 7,641 110 10,994 65 2,083 16 2,164 288,472 194 4,441 88 131 10 12,375 253 3,903 59 1,276 47 1,639 21 563 208,382 114 2,004 31 428 19 8,188 108 -194 -6 991 15 0 0 121 72,612 40 935 9 17 4 3,392 43 780 3 663 19 0 0 0 0

44,681 572 18,078 157 2,533 90 59,273 575 14,592 3 5,587 59 2,598 20 1,239 1526,794 316 12,115 103 1,634 57 37,876 363 11,082 47 2,938 28 0 0 21 21,847 83 423 13 11 4 2,256 91 409 8 500 14 0 0 80 22,471 89 629 10 17 4 3,086 96 615 7 7 4 223 4 604 14

39,544 550 14,559 262 4,410 123 45,784 630 6,240 80 9,209 139 2,198 5 2,618 2225,248 217 5,108 73 880 19 28,731 256 3,483 39 6,467 85 131 1 231 39,222 327 3,717 149 103 25 12,609 425 3,387 98 1,730 122 463 8 905 13

10,746 328 1,649 66 448 46 11,673 303 927 -25 1,949 109 506 15 1,686 2418,882 128 4,345 54 218 7 22,254 161 3,372 33 4,908 35 1,028 2 0 022,736 272 7,865 74 944 53 28,384 267 5,648 -5 3,790 47 803 9 83 63,583 251 1,721 17 229 30 4,017 214 435 -37 281 11 13 1 111 2

12,627 136 1,035 46 19 2 13,110 164 483 28 2,836 30 33 4 258 912,507 238 4,547 39 1,200 28 14,813 205 2,306 -33 1,644 30 30 4 347 1028,016 450 6,351 104 847 72 31,843 477 3,827 27 5,853 114 54 2 245 510,683 314 3,818 104 315 25 13,694 349 3,011 35 2,452 69 1,612 19 1,310 217,675 79 9,600 89 1,912 36 17,045 176 9,370 97 1,643 23 1 1 18 5

17,760 290 4,544 96 108 13 21,650 347 3,889 57 3,098 83 1,322 5 126 105,097 82 492 15 17 1 5,506 93 409 11 50 1 20 1 402 55,696 99 1,187 31 4 4 6,766 116 1,070 17 953 44 797 3 130 27,545 116 4,397 52 1,837 6 10,106 163 2,561 47 354 6 1,488 18 1,533 212,890 91 1,325 14 78 10 4,142 98 1,252 7 274 7 0 0 24 1

19,426 285 3,813 54 2,694 69 18,895 247 -530 -38 2,370 24 3 1 1 36,035 121 1,839 22 171 14 7,410 102 1,376 -19 1,271 24 650 4 1,248 8

41,223 710 5,582 104 2,148 78 40,808 674 -415 -36 8,308 77 1,584 15 1,009 1523,819 308 4,567 39 145 15 28,080 317 4,261 9 5,031 44 284 17 4 24,877 30 194 11 5,069 40 192 10 561 10 347 4 651 9

31,783 329 7,501 116 924 32 35,350 352 3,568 23 8,468 95 67 1 67 114,613 214 7,021 62 280 27 21,192 237 6,578 23 2,317 73 372 5 122 212,224 220 2,831 36 108 12 13,366 234 1,142 14 39 3 145 2 515 1143,145 434 9,816 90 2,288 56 47,380 413 4,235 -21 6,900 78 701 22 304 211,581 37 798 15 1 1 1,889 48 308 11 0 0 0 0 0 0

19,273 245 5,279 43 155 11 24,175 268 4,901 23 1,845 29 580 1 4 23,049 50 372 11 75 1 3,333 58 284 8 47 7 185 2 710 8

20,565 209 2,812 54 185 12 23,035 252 2,470 43 7,334 47 0 0 0 080,025 804 35,497 294 13,529 207 100,238 826 20,212 22 8,441 105 5,689 30 3,524 295,944 85 1,962 52 180 25 7,788 109 1,844 24 545 12 75 4 395 10

986 41 6 4 9 5 965 35 -21 -6 44 3 0 0 35 120,163 255 4,380 81 320 18 24,227 313 4,064 58 3,862 39 360 2 541 526,525 314 2,863 73 254 18 28,234 363 1,709 49 0 0 1,074 9 1,303 11 1,136 30 162 9 706 9 -430 -21 0 0 0 0 0 015,678 102 1,350 22 8 1 16,989 116 1,310 14 4,833 45 864 2 600 413,451 349 3,897 68 463 29 16,209 362 2,758 13 2,870 62 2,794 10 1,699 206,473 65 721 21 0 1 7,196 85 722 20 709 17 482 2 436 5

859,467 12,735 263,538 3,518 49,741 1,578 1,035,937 13,728 176,470 993 147,055 2,109 36,010 320 28,402 436

00

00

AlabamaAlaskaArizonaArkansasCaliforniaColoradoConnecticutDelawareFloridaGeorgiaHawaiiIdahoIllinoisIndianaIowaKansasKentuckyLouisianaMaineMarylandMassachusettsMichiganMinnesotaMississippiMissouriMontanaNebraskaNevadaNew HampshireNew JerseyNew MexicoNew YorkNorth CarolinaNorth DakotaOhioOklahomaOregonPennsylvaniaRhode IslandSouth CarolinaSouth DakotaTennesseeTexasUtahVermontVirginiaWashingtonWashington, D.C.West VirginiaWisconsinWyoming

Total U.S.

MW Units MW Units MW Units MW Units MW Units MW Units MW Units MW Units

Note: a. Approximately 70% of the total is expected to reach commercial start-up in 2008.

00

POWER | January 200842

2008 INDUSTRY FORECAST

Since the beginning of 2002, 102 coal-burning units totaling 5,200 MW have been decommissioned. Another 83 units representing 9,363 MW are scheduled to be shut down for good by the end of 2012.

Natural gas: Still a contenderDuring the past decade, an aggressive push to build gas-fired generat-ing capacity resulted in 300,000 MW being added to U.S. grids. But economic downturns, questionable industry business practices, and closer scrutiny of demand forecasts combined to slow that boom. It ended in 2005—the worst Atlantic hurricane season on record—when storms damaged many rigs in the Gulf of Mexico, driving gas prices above $15/mmBtu. The price surge was a message to the U.S. power industry that depending heavily on one fuel is risky business.

Despite the recent slowdown in activity, natural gas is expected to remain a leading power plant fuel. Gas-fired combustion turbine plants, operating either in simple-cycle or combined-cycle mode, still run cleaner than coal plants (making their permitting easier) and are much faster to build.

Construction kickoffs for gas-fired generating units began declin-ing steadily from their peak in 2001, when units representing more than 73,000 MW broke ground. The slide continued through 2004, when only 5,600 MW of gas-fired capacity followed suit. Since 2005, the pace has picked up, and it looks likely to accelerate. For example, 158 gas-fired units totaling 15,469 MW are currently in construction. The latter number comprises 7,000 MW being built as part of green-field units and 8,456 MW being added to existing plants.

To help meet longer-term demand, 438 gas-fueled units totaling 50,900 MW are in various stages of development. Of those totals, 18 units totaling more than 2,000 MW were scheduled to have bro-ken ground before the end of 2007 (after this issue goes to press), with the other 48,000 MW and change slated to follow by 2015. This year alone will see construction kickoffs for at least 9,000 MW of the 24,000 MW currently under development. The round numbers are

Table 2. U.S. power generation construction kickoff summary (2000–2008) by generation technology. Source: Industrial Info Resources

Unit type

Combined-cyclecombustion turbine

Combined-cyclesingle-shaft system

Combined-cyclesteam turbine with supplementary firing

Combined-cyclesteam turbine withwaste heat only

Hydraulic turbine

Hydraulic turbine, reversible(pumped storage)

Internal combustionengine

Other (solar/fuel cell)

Simple-cyclecombustion turbine

Steam turbine

Turbo expander

Wind turbine

Total

2000 20042001 2003 2005 2006 2007 20082002

Units

196

10

47

28

786

3

8

0

12

192

0

288

2

MW

29,260

2,678

8,758

4,359

69,026

44

410

0

753

337

0

22,422

5

Units

186

1

77

28

817

1

23

0

10

178

0

313

0

MW

30,954

13

15,904

4,741

77,309

8

1,282

0

666

453

0

23,288

0

71

0

15

21

361

0

8

0

3

108

0

135

0

Units MW

0

0

0

0

9,469

3,332

3,660

26,356

277

366

241

9,011

0

Units

46

0

16

8

265

5

26

1

5

104

0

54

0

MW

5,562

0

2,869

1,120

15,704

140

1,567

5

1,261

256

0

2,924

0

Units

24

0

5

10

223

4

19

1

13

107

0

40

0

MW

2,304

0

759

517

9,117

6

840

1

1,561

283

0

2,848

0

Units

17

2

4

6

221

6

30

12

22

89

0

33

0

MW

2,203

800

1,024

591

13,624

73

2,698

92

4,246

178

0

1,719

0

Units

20

0

5

7

227

6

48

2

17

93

2

25

2

MW

2,764

0

731

995

17,442

81

5,205

23

5,723

89

40

1,727

64

Units

26

0

7

4

290

11

79

6

29

57

0

65

6

MW

3,716

0

1,439

630

23,281

65

7,194

50

5,642

250

0

4,220

76

Units

99

0

21

31

731

39

203

26

89

89

7

118

9

MW

15,470

0

4,308

5,068

75,277

371

21,088

610

18,215

456

655

8,092

943

Note: a. Based on construction kickoff dates, not operational dates.

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January 2008 | POWER 43

2008 INDUSTRY FORECAST

necessary because permitting and financing difficulties could delay some projects.

Nuclear: Making a comebackThe drive to diversify generation’s fuel mix may be helped by the possible licensing of dozens of new reactors. They would be the first ordered in the U.S. since 1978, one year before Unit 2 of the Three Mile Island plant in Pennsylvania partially melted down. Cur-rently, nuclear generation supplies about 20% of America’s electricity. Although nuclear plants are more expensive than coal plants (taking into account the costs of licens-ing, decommissioning, and waste disposal), nuclear fuel is half the price of coal, so the plants’ total production costs are about the same: about $30/MWh. Notably, unlike coal plants, nuclear plants emit no CO2, a major contributor to global warming.

Early this decade, reactor vendors and util-ities began lobbying the federal government to reduce the considerable financial risks of building new plants. They succeeded by hav-ing the Energy Policy Act of 2005 include tax incentives and loan guarantees for up to 6,000 MW of new nuclear capacity. Earlier, the Nuclear Regulatory Commission (NRC) had streamlined the lengthy processes for permit-ting and licensing new reactors by creating a new system for issuing combined construc-tion and operating licenses (COLs) for plants and approving reactor designs in advance.

The NRC says it expects to receive applica-tions for 12 new reactors at seven sites within the next few years and 15 more applications over the longer term. Four consortia have al-ready applied for early site permits, using a separate process in which the NRC reviews and approves the suitability of a site before its prospective developers apply for a COL.

In all, developers are currently proposing building 47 new reactors in the U.S. They would be part of 33 projects totaling more than 60,000 MW and would be valued at

more than $106 billion. Given the length of the site permitting and COL processes, it’s conceivable that 19 of the proposed reactors could break ground in 2010, but that’s a very optimistic estimate. Until the timetables are firmed up and financing issues are resolved, the U.S. nuclear power industry will have to be satisfied with incremental upgrades of re-actor capacity. At present, 12 projects of that type totaling $600 million are in the works.

Renewables: Finally going mainstreamCiting the need to displace the use of fos-sil fuels to reduce CO2 emissions and help lessen America’s dependence on imports, 24 states and the District of Columbia have enacted renewable portfolio standards (RPS) that require their regulated electric utilities to get an increasing share of their supplies from wind farms, solar cells, and biomass and geothermal plants. The standards cur-rently in place call for development of more than 55,000 MW of renewable capacity by 2020. Nine other states have introduced RPS bills, and several of the 24 states that have imposed standards are considering moving up the deadline to meet them.

In December 2007, the U.S. Congress extended the federal production tax credit

(PTC) for renewable energy plants by one year, through December 31, 2008. That was the second time Congress approved extension of the PTC just before it expired. From 1999 until 2004, the credit was allowed to expire on three separate occasions, and each time it put a damper on renewable energy devel-opment. The PTC provides a 1.9 cents/kWh tax credit for all electricity generated by a renewable-fuel plant over its first 10 years of operation—if the plant qualified by entering commercial service before the deadline.

With the RPS and PTC incentives in place, investment in renewable energy projects is expected to surpass that in gas-fired projects for the third year in a row. More than 5,000 MW of renewables-fueled plants valued at $7.7 billion broke ground in 2006. That’s a 67% increase over the prior year. For com-parison, investment in new gas-fueled plants covering both years totaled $5.9 billion.

More than 5,200 MW of renewable-fu-eled units broke ground last year by Septem-ber, and another 2,800 MW were scheduled to follow suit by year’s end. All told, 8,000 MW, representing more than $11.7 billion in investments, were expected to begin con-struction in 2007, while over 4,000 MW were scheduled to go commercial by New Year’s Eve.

Table 3. U.S. power generation construction kickoff summary by primary fuel type (2000–2008). Source: Industrial Info Resources

Table 4. Total installed cost of generation by construction kickoff year (in 2006 dollars) by fuel type, in millions of dollars. Source: Industrial Info Resources

Nuclear

Natural gas d

Solar

Total

Fuel oil c

Geothermal

Biomass b

Coal

Wind

Hydro, tidal

Notes: a. Based on construction kickoff dates, not operational dates. b. Biomass includes biodiesel, wood, municipal waste, digestor gas, and landfill gas.c. Fuel oil includes petroleum coke and tire-derived fuel. d. Natural gas includes waste heat projects.

a

0 0

200820062003 2004 2005 2007200220012000Primary fuel category Units

76

3113

0

3581

02

8

786

MW

241

5101,203

0

4466,614

05

410

69,025

Units

19

2109

0

1663

00

23

817

MW

42

611573

0

874,794

00

1,282

77,309

Units

14

15870

23700

8

361

MW

112

544309

0

25,11300

277

26,356

Units

27

2610

5144

00

26

265

MW

84

1,208220

0

14012,485

00

1,567

15,704

Units

26

4550

4114

01

20

224

MW

176

1,314611

0

66,170

01

843

9,121

Units

46

12359

68300

30

221

MW

152

4,195564132

735,811

00

2,698

13,624

Units

74

11153

86602

48

227

MW

112

5,3774734

1216,482

064

5,205

17,442

Units

41

10136

12124

05

79

290

0

MW

637

4,637324

50

6710,249

123

7,194

23,281

Units

62

691939

46285

09

203

732

MW

1,208

21,981820

1,098

1,02627,073

0983

21,088

75,277

Primary fuel 2000 2001 2002 2003 2004 2005 2006 2007 2008

Fuel oil b$602 $286 $155 $110 $305 $282 $24 $162 $410

Geothermal $0 $0 $0 $0 $0 $329 $85 $125 $2,745Hydro, tidal $87 $16 $0 $280 $11 $146 $241 $134 $2,052Natural gas c $33,307 $37,397 $12,557 $6,242 $3,085 $2,905 $3,241 $5,125 $13,537Wind $615 $1,922 $415 $2,351 $1,265 $4,047 $7,807 $10,791 $31,632

Total $35,473 $40,397 $13,891 $10,516 $6,421 $12,895 $18,091 $22,784 $86,521

Biomass a $241 $42 $112 $84 $176 $152 $112 $637 $1,208Coal $611 $733 $653 $1,450 $1,577 $5,033 $6,452 $5,564 $32,971

Notes: a. Biomass includes biodiesel, wood, municipal waste, digestor gas, and landfill gas. b. Fuel oil includespetroleum coke and tire-derived fuel. c. Natural gas includes waste heat projects.

POWER | January 200844

2008 INDUSTRY FORECAST

Dwarfing those annual totals are the more than 82,000 MW of renewable energy proj-ects being developed that have construction kickoffs between 2008 and 2012. Signifi-cantly, 87% of the planned capacity will be wind power, a generation niche in which the U.S. has long been far behind Europe.

Prospects for U.S. wind power have be-come brighter for two reasons: renewal of the PTC and the development of larger and more-efficient wind turbines. Thanks to the federal subsidy, wind farms at sites with fa-vorable characteristics can now compete on price with fossil-fueled plants. Noticing that, investors pushed spending on wind power projects in 2007 to record levels.

Last year in the U.S., new wind farms to-taling more than 4,000 MW were expected to come on-line. By September, 33 projects rep-resenting 3,635 MW had done so. Another 41 farms in 20 states, totaling 3,600 MW, were under construction; another 1,600 MW were in advanced planning for start-up this year. Even if some are delayed, bringing the total for 2007 and 2008 below the expected 8,800 MW, new wind capacity still will represent a significant increase over the 4,873 MW total for 2005 and 2006.

Aside from the need for new or upgraded transmission to link remote wind capacity to

the grid, the rising costs and tighter supply of wind turbines remain the technology’s big-gest obstacles. Neither situation is likely to improve for some time. For example, most of the turbines that will roll off the assembly line this year have already been purchased.

The worldwide equipment shortage has spurred most of the leading wind turbine manufacturers to boost supplies destined for use in the U.S., where demand is set to peak:

■ Since 2001, Spain’s Gamesa has built two state-of-the-art turbine factories in Pennsylvania.

■ In 2005, homegrown Clipper Windpower expanded the annual capacity of its factory in Cedar Rapids, Iowa, from five turbines to 150.

■ Last year, Siemens Power Generation’s new plant in Fort Madison, Iowa, shipped its first wind turbine blade; Acciona Wind-power opened a new factory in the same state; Suzlon Rotor Corp. inaugurated a wind blade nose cone manufacturing plant in Pipestone, Minn.; and Molded Fiberglass Companies broke ground on a factory in Aberdeen, South Dakota, that will build blades for 1.5-MW turbines de-signed and assembled by GE Energy.

■ This year, Vestas Wind plans to open a

turbine blade factory in Windsor, Colo. Meanwhile, in Newton, Iowa (where the legendary Maytag washer/dryer factory is scheduled to close by year’s end), TPI Composites will begin manufacturing blades for GE’s 1.5-MW machines.

■ Further out, TECO-Westinghouse and Composite Technology Corp. have agreed to build a plant in Round Rock, Texas, to make turbines for the latter’s subsidiary, DeWind Inc. Separately, Hendricks In-dustries plans to open a big, $34 million wind turbine tower manufacturing plant in Keokuk, Iowa, creating 350 jobs.

The top three general contractors, which together are building more than 80% of the wind farms under construction, are M.A. Mortenson, D.H. Blattner & Sons, and RES American Construction. ■

—Britt Burt is VP of Power Industry Re-search and Shane Mullins is VP of Prod-

uct Development for the electric power industry at Industrial Info Resources. The

company provides comprehensive mar-ket intelligence about industrial process-

ing, heavy manufacturing, and electric power generation. For more information

on IIR’s products, call 800-762-3361 or visit www.industrialinfo.com.

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www.powermag.com POWER | January 200846

WATER MANAGEMENT

Costlier, scarcer supplies dictate making thermal plants less thirstyThe Energy Information Administration estimates that U.S. thermoelectric gen-

erating capacity will grow from 709 GW in 2005 to 862 GW in 2030 to help meet annual demand increases of 2%. The makeup and cooling water needed by plants generating that increased capacity certainly won’t be available from withdrawal sources, so plant developers and owners will have to apply water-stingy technologies plantwide. As is usually the case, conservation saves money as well as the environment. Here’s a thumbnail economic analysis of some solutions to the water problem.

By Dr. John R. Wolfe, PE, Limno-Tech Inc.

When the well’s dry, we know the worth of water,” wrote Benjamin Franklin in Poor Richard’s Alma-

nac (1746). Power plant owners are becom-ing very familiar with that economic lesson.

The electric power industry requires reli-able supplies of water in large quantities for cooling and—to a lesser extent—for flue gas desulfurization and ash handling. Water use remains a contentious issue for the U.S. in-

dustry, whose plants account for 40% of fresh-water withdrawals nationwide but only 3% of freshwater consumption, according to a 2004 U.S. Geological Survey (USGS) report.

As America’s population and electricity use continue to grow, power plants are increas-ingly competing with farms, factories, busi-nesses, and households for limited supplies of water. Because the growth of fresh water sup-plies is limited, growth in electricity demand

can be met only by developing technologies that reduce the volume of fresh water required per kilowatt-hour of power generated.

Power generators have a vested interest in conserving water to make local and re-gional supplies last longer. Doing so helps guarantee not only future plant operations but also a growing economy with greater electricity demand.

In a 2006 report, the National Energy Technology Laboratory (NETL) projected that the lion’s share of the new capacity in-stalled between 2005 and 2030 will be in arid regions, including southeast, southwest, and western states. Those are the areas where adopting new water-conserving technologies will likely be most cost-effective for plant operators, due to the shrinking availability and the rising cost of water there (Figure 1).

The purpose of this article is not to review all the available conservation technologies but rather to introduce their potential cost savings to power developers. Another aim is to chal-lenge the original equipment manufacturing community to produce engineered products that minimize water consumption and/or use.

Though existing plants can benefit from retrofitting new technologies, the greatest potential cost savings lies in integrating new technologies into new plant designs. The lon-ger amortization period of investment in new plants makes new technologies more attrac-tive for those plants.

Open- vs. closed-loop coolingNot all water withdrawals result in consump-tive use, and this distinction is especially im-portant for the electric power industry. Many older plants use once-through cooling, which heats large volumes of water and then returns that water, with little volume loss, to a river, a lake, or an ocean.

Projected thermoelectric cooling constraint indices in 2025

Highly constrained Moderatly constrained No existing generation, or constraints unlikely

1. Supply vs. demand. The Thermoelectric Cooling Constraint Index is based on the Water Supply Sustainability Index (WSSI), which takes into account the amount of available renewable water and sustainable groundwater use, limits on freshwater withdrawals needed to protect endangered species, an area’s susceptibility to drought, and its expected growth in water use and power production. An area is considered highly constrained if its WSSI is 3 or greater and moderately constrained if its WSSI is between 2 and 3. Source: NETL, 2006

January 2008 | POWER 47

WATER MANAGEMENT

As a result of Clean Water Act Section 316(b) provisions and public pressures, most jurisdictions now discourage or prohibit construction of new once-through cooling systems. A 2002 EPRI report found that a typical system at a plant burning a fossil fuel, biomass, or waste requires withdrawals of 20,000 to 50,000 gallons/MWh, although it only consumes (loses) 300 gal/MWh. How-ever, the large volume of water withdrawn by a once-through system can entrain and im-pinge aquatic organisms, and the discharge of heat to surface waters may have adverse ecological effects. Once-through systems may be retrofitted with helper towers or use groundwater to dilute discharge and mitigate temperature problems.

For new installations, closed-loop (recir-culating) cooling systems are increasingly required. Because recirculating systems cool by evaporation from towers or cooling ponds, they consume more water than once-through systems, but they withdraw a lot less. The actual rates of water withdrawal and con-sumption depend on the plant’s generation technology and environmental conditions. But for a typical plant, as described in the previous paragraph, a closed-loop system would require withdrawals of just 500 to 600 gal/MWh and lose 480 gal/MWh to evapora-tion, according to the 2002 EPRI report.

The changing mix of once-through and recirculating cooling systems—as well as water-conserving improvements to them—enabled the electric power industry to re-duce its water withdrawals per unit of power generated by a factor of three over a 50-year period: from 63,000 gal/MWh in 1950 to 21,000 gal/MWh in 2000 (Table 1). Over the same period, power generation increased by a factor of 15.

Clean water: No longer abundant or freeThe siting of new plants or the expansion of existing ones is dictated by electricity de-mand forecasts. The choice of cooling tech-nology and other decisions affecting water use are part of an overall siting and plant design process, although location and fuel availability are usually more powerful driv-ers than water availability. Next on the list of desirable features is a site that has suffi-cient transmission access and transportation

facilities to supply fuel at an attractive price. These selection factors should be familiar to anyone following the number of large coal projects under development in arid regions of the western U.S.

Recent projects tend to assume that water is available at some price. One developer in the Southwest noted that, “The cost of wa-ter is not an important factor for us, except when water is unavailable at any price.” An-other, in the Southeast, said, “Water is more and more critical, more in terms of availabil-ity than cost.” A third developer, who spe-cializes in expanding existing plants rather than building new ones, noted that “The cost of water is going up, and water from watersheds is overappropriated. There is a tendency to expand at existing sites where water is available.”

The cost of acquiring water depends on its local abundance or scarcity, water rights, and use rules. Where water is abundant and local regulations permit, the cost of acquiring wa-ter for a new plant may be limited to investing in wells or surface water intakes. Preventing fish entrainment and limiting impingement mortality may be costly when surface water is used. Water rights laws govern allocation in the West, making water costly and possi-bly unavailable during droughts. The cost of acquiring water varies widely, from as low as 50 cents/1,000 gallons (kgal), where water is abundant and regulations permit, to as much as $3/kgal where water is very scarce and rights must be acquired from existing owners (Table 2).

The cost of delivering water depends on distance and terrain but varies over a nar-rower range than acquisition cost. Research shows this component of water cost can be as little as 13 cents/kgal or as much as $1.20/kgal.

The cost to treat and dispose of cooling water varies much more widely, depending on the characteristics of the raw water. Sur-face water may be suitable for cooling with minimal treatment or may require removal

of suspended solids. Because effluent from wastewater treatment plants is typically treat-ed to make it suitable for discharge, it is usu-ally of fairly high quality. However, nutrients and bacteria may restrict wastewater’s use for cooling unless the power plant treats it further (see POWER, May 2006, “Recycling, reuse define future plant designs”).

Fresh groundwater has higher concentra-tions of dissolved solids that can become scale unless they are removed by pretreat-ment in a closed-loop cooling system. Saline water from the ocean or coastal areas also requires treatment and/or the use of special corrosion-resistant materials to make it suit-able for plant use. Degraded waters from coal and oil production may be available, but they have much greater pretreatment re-quirements. For example, low pH is an issue for water pumped from spent coal mines, and the effluent of oil and gas well opera-tions can have high levels of salts, silica, and hardness. And because recirculating cooling water also concentrates dissolved constituents in cooling tower blowdown, it may need to be post-treated if it is dis-charged to surface waters.

EPRI’s “Comparison of Alternate Cool-ing Technologies for U.S. Power Plants” (2004) determined that the cost of pre- and post-treating available water can range from as low as 22 cents/kgal (where treatment re-quirements are minimal) to as much as $4.28/kgal (if the water left over from oil and gas exploration is used).

As Table 2 shows, the sum of the medium estimates of component costs is $2.82/kgal. It is unlikely that a water source would be used if the costs of acquiring, delivering, and treating/disposing of it were all at the high or low end of their ranges; a reasonable range for the overall cost of water is $1/kgal to $4/kgal.

Water withdrawals (billions of gallons)Power generated (billions of MWh)Water withdrawal efficiency (gal/MWh)

1950

14,5000.23

63,000

1960

36,5000.61

60,000

1970

62,1001.28

49,000

1980

77,0002

39,000

1990

71,0002.68

27,000

2000

71,0003.45

21,000

Table 1. Water use efficiency. These were the historical generation and water with-drawal and efficiency values for closed-loop cooling systems serving U.S. coal-, biomass-, and waste-fired power plants. Sources: USGS and EIA Activity Low Medium High

Acquisition $0.50 $1.25 $3.00

Delivery $0.13 $0.57 $1.20

Treatment/disposal $0.22 $1.00 $4.28

Totals $0.85 $2.82 $8.48

Table 2. Water costs. Here are recent representative costs of acquiring, transport-ing, and treating/disposing of 1,000 gallons of water. A reasonable range for the overall cost of water is $1/kgal to $4/kgal. Source: EPRI, 2004

Water is more and more critical, more in terms of availability than cost.

POWER | January 200848

WATER MANAGEMENT

This wide range of water costs has im-portant implications for the sustainability of supplies. Because costs vary widely from one location to another, so does the attractiveness of water conservation technologies across lo-cations and regions. The development of new technologies increases the options for plant developers and decision-makers, enabling them to reduce water-related costs and plant profitability.

Better cooling options can even make it easier to site a plant near its market and fuel supplies, potentially boosting profits. Ideally, water availability and cost should not be sec-ond-tier considerations during the planning of a power project; they should be as impor-tant as electricity demand and fuel availabil-ity. When more technological options—plus more-reliable information about water sup-plies and costs and the economic benefits of new technologies—are available, planners can do a better job of planning and siting new capacity to use water supplies wisely.

Recycling waterAs mentioned earlier, closed-loop cooling systems require less fresh water withdraw-als than once-through systems, but they consume more water due to evaporation. In addition, water may be consumed by flue gas scrubbing and be lost to cooling tower blowdown. The development of new tech-nologies could reduce losses from each of these processes, as could the reuse of “gray water” for cooling.

The 480 gal/MWh loss to evaporation from a typical coal-fired power plant rep-resents the greatest opportunity for sav-ings. Evaporative losses can be reduced if water vapor can be condensed and returned

to the cooling system. Small-scale tests of one technology, which uses crosscurrents of ambient air for condensation, show po-tential for capturing 12% to 30% of evapo-rative losses if engineered to full scale. A 2006 paper by Ken Mortenson argued that this technology could cut losses by 60 to 140 gal/MWh, with the high end applying to hotter climates.

This reduction in water losses can be trans-lated into dollar savings at the plant level by assuming a cost of water and a plant capacity. Using the representative midrange total water cost of $2.82/kgal developed earlier, the sav-ings would range from $0.17 to $0.39/MWh. For a 350-MW baseload plant operating year-round, savings from reducing evapora-tion from its cooling towers would amount to between $500,000 and $1,200,000, with a midrange value of $870,000. Increasing the towers’ cycles of concentration and reducing blowdown losses (see below) might save the same plant another $300,000 to $1,200,000 annually.

Beware of blowdownAs water evaporates from a cooling tower, the concentrations of dissolved and suspend-ed solids in the remaining water increase. To minimize scaling, fouling, and corrosion of the cooling system, these concentrations are reduced by blowdown. Blowdown is the term for the discharge of water from the cooling system and its replacement by fresh makeup water taken from a river, lake, or well. The term “cycles of concentration” describes the proportion by which evaporation increases constituent concentrations (assuming the typical evaporation rate of 480 gal/MWh). For example, at two cycles of concentration,

evaporation doubles constituent concentra-tions, relative to intake water.

The development of cooling system mate-rials that are resistant to scaling, corrosion, and fouling may make it possible to operate at higher solids concentrations, significantly reducing blowdown losses. A study by EPRI and the California Energy Commission found that doubling cycles of concentration from 4 to 8, which exceeds the usual allow-able range, could reduce blowdown by about 100 gal/MWh (Figure 2). (See the POWER articles, “Southern California Public Power Authority’s Magnolia Power Project” in September 2005 and “High Desert Power Plant” in September 2003, for examples of plants running high cycles-of-concentration cooling towers with zero liquid discharge systems.)

As we did for reductions in evaporative losses, we can translate reductions in blow-down water losses into dollar savings at the plant level by assuming a cost of water and a plant capacity. Using $1 to $4/kgal for the total water cost range, savings from reducing blowdown losses would come in at 10 to 40 cents/MWh. As mentioned earlier, for a 350-MW baseload plant operating year-round, the potential savings would be $300,000 to $1,200,000, with a midrange value of $860,000.

Scrubbing waterThe ratcheting down of emission levels for sulfur dioxide has sparked a mini-boom in the market for flue gas desulfurization (FGD) systems, or scrubbers. NETL estimates that the size of the U.S. FGD market is expected to increase by more than 100,000 MW over the next 10 years. Although water require-ments for scrubbing are a fraction of those needed for cooling purposes, FGD units re-quire a significant amount of water to pro-duce and handle the various process streams (limestone slurry, scrubber sludge, and the like). NETL’s 2005 “Power Plant Water Usage and Loss Study” found that makeup water requirements for the FGD island at a 550-MW (nominal) subcritical coal-fired power plant are about 570 gallons/minute (gpm), vs. about 9,500 gpm for cooling wa-ter makeup.

Flue gas scrubbing can be accomplished with either dry or wet systems. Wet scrub-bers entrain the flue gas in a water spray, capturing sulfur dioxide and other pollutants, which are then removed by creating an alka-line slurry. Dry scrubbing injects the alkaline particles directly into the flue gas stream, ob-viating the need for water, but the more lim-ited contact between reactants in the absence of water results in lower pollutant removal efficiencies.

230

162

66

Wat

er u

se (g

al/M

Wh)

Cycles of concentration3 4 5 6 7 8 9 10

2. Blowdown blowup. Typical water losses from cooling towers at various cycles of concentration. Source: EPRI, 2007

January 2008 | POWER 49

WATER MANAGEMENT

New technologies that reduce or recover evaporative losses from scrubbing flue gas, or increase the removal efficiency of dry scrubbing, could reduce water use and as-sociated costs. Another way to quantify the water requirements for a typical wet scrub-ber is to determine the amount of water that a plant could save by shifting from wet to dry scrubbing, or by capturing all of the evapora-tion produced by wet scrubbing. NETL came up with a figure of 25 gal/MWh. Again us-ing $1 to $4/kgal as the range of total water costs, the savings would amount to 2.5 to 10 cents/MWh. For our 350-MW baseload plant operating year-round, the potential annual savings from shifting from wet to dry scrub-bing ranges from $75,000 to $300,000, with a midrange value of $220,000.

If all three loss processes (evaporation from cooling towers, blowdown, and flue gas scrubbing) could be simultaneously reduced at an existing 350-MW coal-fired plant, the total annual cost savings would be $875,000 to $2,700,000 (depending on climate and the cost of water), with a midrange total of $1,950,000. Figure 3 shows the potential savings for each process, assuming an in-termediate cost of $2.82/kgal for total water use. Most of the savings are from reducing blowdown and evaporative losses, with the elimination of losses from wet scrubbing a minor contributor.

Other sources of waterWhere clean water is unavailable at a reason-able cost, lower-quality nontraditional water supplies may be good substitutes, as long as depreciation of cooling systems can be minimized by limited pretreatment of intake

waters. Potential sources of degraded water include treated urban wastewater, storm wa-ter, mine drainage, quarry dewatering, and water produced by oil and gas extraction (see POWER, March 2007, “Reclaimed cooling water’s impact on surface condensers and heat exchangers”).

Wastewater from public treatment works can be very affordable, at the low end of the treatment/disposal costs shown in Table 2, because such water has already been treated. This water source will also grow sustainably, because growing populations that require more electricity also generate growing waste-water flows. New sewage flows, just from domestic water use alone, can be expected at a rate exceeding 40 gal/day per capita. About 16 gal/day per capita are sufficient for new power generation, assuming current average rates of 33 kWh per day of electricity demand per capita and water consumption for power generation of 480 gal/MWh.

Where population growth is insufficient for increasing wastewater flows, advances in technologies that enable the use of de-graded waters may also present substantial opportunities for cost savings. As Figure 4 shows, the cost of treatment required to safely use degraded waters can exceed $4/kgal for produced waters and agricultural return waters, making it the largest compo-nent of the cost of water. At such a high cost, use of these degraded waters is not often competitive. However, advances in the abil-ity to use degraded waters without extensive pretreatment—such as spray-enhanced dry cooling—could reduce the overall cost of cooling water, making degraded water com-petitive with more traditional groundwater

and surface water sources.To roughly estimate the potential saving

from advances in the use of degraded waters, we can assume a reasonable decrease in the cost of pretreatment, based on the range of current costs. Water resulting from oil and gas extraction, and agricultural return wa-ters, cost $4/kgal or more to treat—about four times what it costs to treat fresh water. It is unlikely that treatment technologies and/or the development of materials compat-ible with degraded waters will eliminate the gap. It is possible, however, that the differ-ence in treatment costs could be significantly reduced, by as much as 25 to 75 cents/kgal. For our 350-MW baseload plant that requires 480 gal/MWh, the savings would amount to $370,000 to $1,100,000, with a midrange value of $740,000.

Other cooling optionsDry cooling eliminates a thermal power plant’s dependence on cooling water. The plant’s steam is condensed inside finned tubes by blowing air across their exterior surfaces. The challenges of dry cooling in-clude much higher capital and installation costs, a high efficiency penalty, increased exhaust gas emissions, and load limitations on hot days.

Currently, dry cooling is used, or viewed as an option of last resort, where water is very costly or limited in availability. There are now several plants in operation or under construction that use dry cooling; most are gas-fired, combined-cycle units. As a result, in the U.S. there is only limited experience with dry cooling of baseload-scale plants. Advanced technologies for dry cooling

7

6

5

4

3

2

1

0

Annu

al w

ater

cos

t ((m

illio

ns $

)

Typical After potentialreductions

Blowdown Evaporative Scrubbing

3. Saving water, and dollars. Po-tential savings from reducing three process water losses at a 350-MW coal-fired power plant, assuming a total water cost of $2.82/kgal. Source: EPRI, 2007

4. The cost of using degraded water. Representative water treatment costs per 1,000 gallons from various sources. Source: EPRI, 2004

$4.50

$4.00

$3.50

$3.00

$2.50

$2.00

$1.50

$1.00

$0.50

$0.00

$/kg

al

Recycledwastewater

treatment planteffluent (coastal)

Fresh water(desert)

Fresh water(valley)

Produced water(valley)

Agriculturalreturn water

(desert)

POWER | January 200850

WATER MANAGEMENT

larger plants would be of great interest to power project developers if the technologies would reduce the efficiency and capital-cost penalties.

One developer framed the problem suc-cinctly as follows: “We wouldn’t go to dry cooling unless we really had to, because of enormous capital and operating costs, and lower plant efficiency.” Efficient air cool-ing options must be expanded and made less costly for future plants.

Hybrid cooling represents a middle ground that may be more appealing and feasible for baseload plants. Hybrid cooling systems use a combination of both wet and dry cooling technologies to conserve wa-ter. Although they decrease the hot weather penalty, they reduce but don’t completely eliminate the need for cooling water. Hy-brid systems can limit annual water use to 2% to 5% of what wet recirculating cool-ing systems use, although 20% to 80% is a more typical range. Generation efficiency and capacity generally increase with greater water use.

It is only where the costs of water are highest that air cooling is cost-competitive with water cooling (Figure 5). For example, if our 350-MW reference plant were in El Paso, Texas, dry cooling would be cost-com-petitive only when the cost of water exceeds about $3/kgal. Above that level, dry cooling would be preferred because its cost is unaf-fected by the cost of water.

The magnitude of potential savings for generators in warmer climates approaches 20% of cooling costs. Look at the cost curves of Figure 5 for plants in El Paso, Texas, and Portland, Ore. (see POWER, September 2007, “Port Westward Generating Plant”). The difference is due entirely to El Paso’s hot weather penalty, which is on the order of $1.5 million/year in cooling costs, according to a 2004 EPRI report. The goal of ongoing research into improved air-cooled and/or

hybrid technologies is to reduce costs for a plant of this capacity by a significant share. A reduction of 33% to 66% in the hot weather penalty would produce annual savings of $500,000 to $1,000,000.

Running the numbersPotential cost savings have been estimated above for several innovative applied technol-ogies. To provide a consistent point of refer-ence, Table 3 can be used to roughly estimate the potential annual cost savings available to a typical 350-MW coal-burning plant from capturing evaporation, reducing blowdown, using degraded waters, and adopting dry or hybrid cooling.

Any of the estimated savings shown in the table would be sizable enough to sig-nificantly increase a power plant’s profit-ability. For example, the production costs of a 350-MW baseload coal-burning plant run about $100 to $125 million annually, based on a levelized cost ranging from $33 to $41/

MWh. With the exception of dry scrubbing, each technology listed in Table 3 has the potential to reduce annual production costs by about 1%, increasing profitability by the same percentage.

Because profit rates for generating plants currently average about 7% to 8% of costs, implementing these water-conservation tech-nologies, alone or in combination, could raise profit rates by 1 to 3 percentage points, from 7% to 8% to an improved 8% to 11%. Measured in millions of dollars, that’s a sub-stantial gain. ■

—This article was based on the Limno-Tech report, “Program on Technology Innovation: An Energy/Water Sustain-

ability Research Program for the Electric Power Industry.” EPRI, Palo Alto, CA: 2007.

1015371.Dr. John R. Wolfe, PE (jwolfe@limno.com), was the principal investigator

for Limno-Tech Inc. Paul L. Freedman, PE, and M. Catherine Whiting were coauthors

of the report.

5. Breakeven points. Comparing the costs of wet and dry cooling for two hypo-thetical 350-MW plants—one in Portland, Ore., and the other in El Paso, Texas. Source: EPRI, 2004

Cool

ing

cost

($M

/yr) 8

6.5

Wet (all plants)

Dry(El Paso)

Dry(Portland, OR)

Cost of water ($/kgal)1 2 3 4

Conservation technology

Capture evaporation

Reduce blowdown

Dry scrubbing

Use of degraded waters

Dry or hybrid cooling

Low

$500,000

$300,000

$75,000

$370,000

$500,000

Medium

$870,000

$860,000

$220,000

$740,000

$750,000

High

$1,200,000

$1,200,000

$300,000

$1,100,000

$1,000,000

Table 3. Cost savings. These are the estimated annual benefits for a typical 350-MW coal-burning plant from using different water use reduction technologies. Source: EPRI, 2007

Water usage researchFor more information about the subject of

power plant water usage, consult the fol-

lowing sources, which informed the writ-

ing of this article:

■ California Energy Commission. 2003.

“U.S. Per Capita Energy Use by State in

2003.” www.energy.ca.gov/electricity/

us_percapita_electricity_2003.html.

■ DeFillippo, M. 2003. “Use of Degraded

Water Sources as Cooling Water in

Power Plants.” EPRI and California En-

ergy Commission.

■ Energy Information Administration.

2004. Annual Energy Review 2003.■ EPRI. 2002. “Water and Sustainability

(Volume 1): Research Plan.”

■ EPRI. 2004. “Comparison of Alternate

Cooling Technologies for U.S. Power

Plants: Economic, Environmental, and

Other Tradeoffs.”

■ EPRI. 2007. “Program on Technology

Innovation: An Energy/Water Sus-

tainability Research Program for the

Electric Power Industry.” Prepared by

Limno-Tech Inc.

■ Metcalf & Eddy Inc. 1991. Wastewater Engineering, Disposal and Reuse, 3rd

ed. New York: McGraw-Hill.

■ Mortenson, Ken. 2006. “Use of Air2Air

to Recover Fresh Water in Evaporative

Cooling at Coal-Based Thermoelectric

Power Plants.” Symposium on Western

Fuels. Denver, Colo.

■ National Energy Technology Labora-

tory. 2005. “Power Plant Water Usage

and Loss Study.”

■ National Energy Technology Labora-

tory. 2006. Estimating Freshwater Needs to Meet Future Thermoelectric Generation Requirements. DOE/NETL–

2006/1235.

■ U.S. Geological Survey. 2004. Estimat-ed Use of Water in the United States in 2000. USGS Circular 1268. http://

pubs.usgs.gov/circ/2004/circ1268.

January 2008 | POWER www.powermag.com 51

STEAM TURBINES

Eliminating oil whip–induced vibration after a steam turbine retrofitNobody expected driveline vibration to occur after a flawless retrofit of a 200-

MW steam turbine. But when it did, Mitsubishi Power Systems and Exelon vibration specialists identified the symptoms and rapidly narrowed the list of possible causes. Confounding factors made the root cause difficult to identify, but the experts pinpointed the problem, made necessary hard-ware modifications, and placed the turbine back in service in a week.

By Craig C. Jennings, Exelon Power

Extending the economic operating life of aging steam plants remains a priority at many utilities, given the challenge of

obtaining permits for new generation and the lower cost of life-extension projects. More than half of U.S. coal-fired plants are over 30 years of age, and 10% are more than 50 years old. These veterans still have a lot of fight left in them, given an overhaul or two. But such work can uncover unexpected ailments, as operators at the aging Cromby Generating Station (Figure 1) learned.

Exelon’s Cromby Generating Station, lo-cated in Phoenixville, Penn., consists of two units: Unit 1 is a coal-fired 144-MW plant; Unit 2 is a 202-MW unit that burns gas or No. 6 fuel oil, depending on market conditions. Unit 1 has accumulated more than 330,000 fired hours since it began commercial service in 1954. Unit 2, commissioned in 1955, re-mains a favorite dispatch unit in the Exelon fleet and dispels the myth that “it’s the miles and not the age” that determine when a unit should be retired.

Rotor transplantUnit 2, the focus of this case study, is a conventional steam plant with a three-cas-ing, single-driveline steam turbine (one HP, one IP–single-flow LP [IP-SFLP], and one double-flow LP [DFLP]) originally built by Westinghouse (Figure 2). Mitsubishi Power Systems Inc. (MPS) was awarded a contract to retrofit and upgrade the steam turbine to extend its service life. Generating 4% more power with the more-efficient turbine was a welcome side benefit of the project.

Figure 2 also illustrates the unit’s rotor bearing arrangement. In this configuration, bearing No. 4, between the IP-SFLP and the DFLP (bearing No. 5), is shared by the

two cylinders. Figure 3 compares cross sec-tions of the old and replacement HP steam turbines.

The retrofit project replaced the HP rotor and diaphragms but reused the existing out-er casing. The original Curtis control stages

were replaced with a single, higher-effi-ciency Rateau stage, and the reaction blades were redesigned with the latest 3-D design tools. The HP turbine’s inner casing, blade, and dummy rings were replaced; the HP ro-tor bearings were rebabbitted; and thermo-

1. Fifty years and counting. Exelon’s Cromby Station has been in commercial service for more than 50 years. Upgrades to Unit 2’s steam turbine should extend the plant’s life for a couple more decades, at least. Courtesy: Exelon Corp.

BearingNo. 1

High pressure Intermediate pressure–single-flow low pressure

Double-flowlow pressure Generator

2 3 4 5 6 7

2. Long driveline. The rotor arrangement of Unit 2 at Cromby Generating Station. Source: MPS

POWER | January 200852

STEAM TURBINES

couples for bearing metal temperature were installed. Farther down the driveline, one row of LP L-0 blades and three rows of LP L-1 blades were replaced. The addition of orthogonal vibration measurement instru-mentation completed the scope of work. Plant engineers showed excellent foresight in adding this new vibration instrumenta-tion—as you’ll appreciate in a moment.

The upgrades were completed without in-cident, and the unit was started on Novem-ber 17, 2003, for testing. Loading of the unit and overspeed tests were also performed without any major problems. However, vi-bration instability, or oil whirl vibration, in the HP bearings at low-load operating con-ditions was soon observed. In the follow-ing days, several field balancing runs were performed to reduce the vibration levels of bearings 3, 4, and 5. On November 20, af-ter sustaining low-load operation for several minutes, a rather sudden synchronous vibra-tion increase was recorded in bearing 2 (and in bearing 1 to a lesser extent) that prompted a trip of the unit.

During the coast-down, a sudden subsyn-chronous vibration spike was recorded at ap-proximately 3,500 rpm with a filtered 0.5X value in excess of 15 mils (with direct read-ings of almost 20 mils).

Bad vibesThe old HP turbine had had a history of unstable behavior before the retrofit and had experienced sporadic subsynchronous vibration. However, pre-outage detailed vi-bration data were not available for precise analysis because the unit was not equipped

with the instrumentation package found on late-model turbines.

The rotor bearing system stability of the HP turbine with the original “partial center slot type” bearings (Figure 4) had been ana-lyzed before the outage and was found to be satisfactory with the heavier new rotor. The option of making dimensional changes in the center slot to improve the stability margin was dismissed because of the relatively el-evated drain temperature of the HP bearings (180F for an oil supply of 104F).

Vibration data collected on November 19 (before the trip) still showed sporadic

subsynchronous vibration, which now ap-peared during the acceleration ramp-up at approximately 2,840 rpm and disappeared at approximately 3,490 rpm (Figure 5). This sporadic behavior continued during several subsequent operational tests when loading the unit to baseload operation. The only com-mon thread was the unpredictable timing of the vibration.

The team determined that the high syn-chronous vibration recorded on November 20 was caused by a severe rubbing condition between the shaft and the bearings experi-enced during a normal shutdown, causing

3. Fits like a glove. Mitsubishi Power Systems engineered a new direct replace-ment HP steam turbine to fit inside the cas-ing of the old steam turbine. Shown are cross sectional drawings of the original (top) and new (bottom) HP steam turbines. Source: MPS

4. Recycled bearings. The HP turbine’s lower-half bearings with a partial center slot were analyzed as part of the retrofit turbine design and were found to be adequate for the new, heavier rotor. All bearings were rebabbitted during the project. Courtesy: MPS

5. Unexpected spike. Subsynchronous vibration during a start-up with the new HP tur-bine is shown inside the red circle. Source: MPS

January 2008 | POWER 53

STEAM TURBINES

the unit to trip on high vibration. The internal rubbing was quickly identified by a large and rapid increase in the synchronous vibration component with large changes in phase angle (Figure 6). At the moment of the trip, the subsynchronous component was negligible, but it suddenly increased during the coast-down that followed the trip (Figure 7). Over-all (nonfiltered) vibration during coast-down after the instability was triggered approached 20 mils (Figure 8).

Flexible shaftThe original steam turbine design included bearing vibration measurement in only one direction. The upgrade’s scope of work added additional, orthogonal vibration mea-suring capability on all bearings. This new instrumentation also allowed operators to gather shaft average centerline data, which was extremely helpful in diagnosing the new HP turbine’s vibration problems.

Figure 9 illustrates the average centerline of bearing 2 from cold start-up conditions (bottom of the plot) to the relatively hot shutdown conditions (last point to the right). The plot clearly indicates a shift of the rotor centerline toward the right side of the bearing during operation. Additionally, the rotor’s stationary position was displaced, relative to its pre-starting position, by almost 5 mils af-ter stopping, in both vertical and horizontal directions.

The only explanation for this behavior is either actual movement of the shaft center to the right side of the bearing (in the opposite direction of the expected shaft locus) or rela-tive movement of the sensor with respect to the bearing center.

Tracking sensor movement relative to the shaft. Bearing No. 2’s vibration sensors were installed in the pedestal cover at a rela-tively long distance from the rotor surface. Thermal expansion–caused movement of the pedestal cover relative to the bearing resulted in the misleading indication that the rotor po-sition at rest, before starting, and after shut-ting down had changed.

Investigators determined that the induced movement of bearing 2’s pedestal cover did result in the erroneous conclusion that the ro-tor position at rest was different at cold and hot conditions and that this was not part of the root cause of the vibration increase.

Factoring in the steam turbine valve sequence. Steam is admitted to the HP tur-bine through eight different nozzles located in the periphery of the HP turbine’s first stage. The nozzles are designed to gradu-ally open during start-up to carefully con-trol steam flow into the turbine’s governing stage. Investigators found that the order in which the eight nozzles are sequenced af-

6. Rubbed the wrong way. A large synchronous vibration excitation in the HP turbine was induced by a rubbing condition. The polar plot shown is for bearing No. 2. Source: MPS

7. Stuttering stop. A sudden increase in subsynchronous vibration during coast-down was also caused by rubbing. Source: MPS

8. Shake, rattle, and roll. Overall vibration reached 19.7 mils peak-to-peak during the coast-down after the trip. Source: MPS

If a variable isn’t measured, trend analysis isn’t possible.

POWER | January 200854

STEAM TURBINES

fects the bearing loading as the direction of the reaction force on the rotor changes (Figure 10).

Whenever nozzle valve 3 opens (at around 60 to 70 MW), a bearing load increase is ob-served. Bearing loading is clearly reduced after nozzle valve 4 opens at approximately 50% load (about 100 MW). The governor valve sequence related to 25% and 50% steam admission flow corresponds to the lightest load condition of the rotor, and it unloads bearings 1 and 2. A moment is also introduced that affects loading conditions

on bearings 1 or 2, depending on the nozzle valve sequence.

Measuring the uneven movement of bearings 2 and 3 thrust pedestals during thermal expansion. The horizontal thermal expansion of the bearing pedestal between the HP and the IP-SFLP turbines was measured by installing dial gauges at the base of the pedestal base plate. Measurements revealed uneven movement of the pedestal referenced to the shaft centerline.

Measurements of the horizontal movement of the pedestal between HP and IP-SFLP tur-

bines revealed uneven thermal growth dis-placement. This movement induced angular deviation between the rotor and bearings 2 and 3. This deviation caused movement of the rotor at bearing 2, away from the normal shaft centerline position on the right side of the bearing.

Pedestal movement readings at the gen-erator and governor ends of the driveline were significantly different (Figure 11). The relative end-to-end change in pedestal posi-tion was a maximum of +6 mils and a mini-mum of –5 mils. This displacement caused

1210

86420

–2–4–6

Left direction

Right direction

Base

mov

emen

t (m

ils)

10 p.m. MidnightDay 1 Time Day 2

10 p.m. MidnightDay 1 Time Day 2

Base (generator side) Base (governor side) Governor side minus generator side

Load

(MW

)

250

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100

50

0

MW

10. Order matters. HP turbine bearing No. 2 loading was found to be a function of the generator load and the sequencing order of the eight nozzle valves. Source: MPS

7.75

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Bear

ing

surfa

ce p

ress

ure

(kg f

/cm

2 )

0 50 100 150 200 250

#5 valve opens, and the vertical

downwardforce increases.

#3 valve opens, and the vertical downward force

increases.

25% admission

#6 valve open condition

50% admission

Generator output (MW)

9. Tracking shaft movement. Newly installed instrumentation added the ability to track the HP turbine shaft average centerline. This chart shows the shaft movement inside bearing No. 2. Source: MPS

Rotor at rest

11. Measuring movement. The horizontal thermal growth of the pedestal between the HP and IP-SFLP turbines was measured during a typical turbine start-up, at full-load operation, and then at 25% load. Source: MPS

January 2008 | POWER 55

STEAM TURBINES

the observed angular deviation of the bearing with respect to the rotor centerline. The lower chart in Figure 11 shows the loading condi-tion of the unit during measurement of the pedestal’s horizontal movement.

Inspired solutionThe stability margin of the replacement rotor-bearing system was analyzed throughout the entire range of loading conditions. Particular emphasis was placed at 25% load, where the rotor bearing system has the lowest loading. Bearing metal temperature data were also collected during the turbine tests and revealed additional clues to the root cause of turbine vibration (Figure 12). The metal temperature “mirrors” the changes in calculated bearing pressure changes induced by the governor valve sequencing. This is clearly confirmed by a comparison of the trends in Figures 10 and 12.

The subsynchronous vibration experi-enced by this plant for many years before the upgrade project had been sporadic and insignificant enough to have no appreciable impact on total measured vibration. After all, if a variable isn’t measured, trend analy-sis isn’t possible. This “dormant” unstable condition was theorized to be the cause of the sudden increase in the subsynchronous component due to an unknown and unex-pected excitation. In this particular case, investigators determined that the rubbing condition (illustrated in Figure 6) was the excitation source causing the sudden in-crease in subsynchronous, or oil whip insta-bility, vibration.

But what caused the original rubbing, es-pecially given that the turbine was initially started and loaded without any evidence of rubbing? Evidence of the rubbing was clearly seen in a photo of the labyrinth seals taken after excessive vibration was observed during the November 20 coast-down (Figure 13).

The solution to both observed problems was to increase the stability margin of the ro-tor-bearing system by modifying the bearing geometry. This one modification increased the stability margin of the HP rotor-bearing system under rubbing conditions and nozzle valve bearing-loading conditions.

The original HP bearings were of the “partial center slot” type with a 0.96-inch slot in the lower half. The HP bearings were modified by increasing the slot width by 0.61 inch—to 1.5 inch—in order to increase the HP rotor bearing system’s stability margin.

Modification of the bearings—including their removal, preparation of the drawing with the modified geometry, machining of the lower half, and reinstallation—was per-formed in less than one week. The unit was

restarted on December 2 and demonstrated a clear reduction in subsynchronous vibration, which enabled the unit to return to commer-cial operation. ■

—Craig C. Jennings (craig.jennings@exeloncorp.com)

is a senior rotating equipment engineer for Exelon Power.

180

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p (F

)

0 50 100 150 200 250Load (MW)

Bearing #1 Bearing #2 Bearing #3 Bearing #4 Bearing #5

12. Temperature fluctuations. Bearing metal temperatures were also measured as a function of load. The general shape of the curve is similar to the bearing loading shown in Figure 10. Source: MPS

13. There’s the rub. Evidence of rubbing found after the large vibration event. Courtesy: MPS

www.powermag.com POWER | January 200856

POWER QUALITY

Protecting plant equipment from voltage sags Immunity from voltage sags is vital for reliable operation of our ever-more-

sophisticated electronic controls and equipment. Every electrical product should be able to ride through typical voltage sags, but in many cases the first sag test occurs after equipment is installed and in operation. Select the appropriate sag immunity specification and equipment compliance testing, and you’ll be glad you did.

By Andreas Eberhard, Power Standard Labs

Modern equipment can be sensitive to brief disturbances on utility power mains. Electrical systems are subject

to a wide variety of power quality problems that can interrupt production processes, affect sensitive equipment, and cause downtime, scrap, and capacity losses. The most common disturbance, by far, is a sag: a brief reduction in voltage lasting a few hundred milliseconds.

Sags are commonly caused by fuse or breaker operation, motor starting, or capaci-tor switching, but they are also triggered by short circuits on the power distribution system caused by such events as snakes slithering

across insulators, trenching machines hitting underground cables, and lightning ionizing the air around high-voltage lines. Many utili-ties report that 80% of electrical disturbances originate within the user’s facility.

A decade ago, the solution to voltage sags was to try to fix them by storing enough en-ergy somehow and releasing it onto the AC mains when voltage dropped. Some of the old solutions included an uninterruptible power supply (UPS), flywheels, and ferro-resonant transformers.

More recently, engineers have realized that voltage sag is really a compatibility problem

with at least two classes of solutions: You can improve the power or you can make the equip-ment tougher. The latter approach is called “voltage sag immunity,” and equipment man-ufacturers have several compliance standards that you should be aware of when specifying future equipment purchases (Figure 1).

Standards developedThree main primary voltage sag immunity standards are discussed in the following paragraphs: IEC 61000-4-11, IEC 61000-4-34, and SEMI F47. There are others in use—such as IEEE 1100, CBEMA, ITIC,

1. Immunize your plant. Voltage sag immunity testing has been common in the semiconductor industry for years and has proved its economic value. New IEC standards for voltage sag immunity will expand this kind of testing and certification to other industries. Courtesy: Power Standard Labs

January 2008 | POWER 57

POWER QUALITY

Samsung Power Vaccine, international stan-dards, and MIL-STD—but the first three seem to have the widest acceptance in the marketplace. (IEC is the International Electrotechnical Commission, SEMI is the Semiconductor Equipment and Materials Institute, CBEMA is the Computer Busi-ness Equipment Manufacturers Association, ITIC is the Information Technology Institute Council, and MIL-STD is the U.S. Defense Department’s specification.)

IEC 61000-4-11 and IEC 61000-4-34 are a closely related set of standards that cover voltage sag immunity. IEC 61000-4-11 Ed. 2 covers equipment rated at 16 amps per phase

or less while IEC 61000-4-34 Ed. 1 covers equipment rated at more than 16 amps per phase. The latter was written after IEC 61000-4-11, so it seems to be more comprehensive.

SEMI F47 is the voltage sag immunity standard used in the semiconductor manu-facturing industry, where a single voltage sag can result in the multi-million-dollar loss of product if a facility is not properly protected. The semiconductor industry has developed specifications for its manufacturing equip-ment and for components and subsystems in that equipment. Enforcement is entirely cus-tomer-driven in this industry, as semiconduc-tor manufacturers understand the economic consequences of sag-induced failures and generally refuse to purchase new equipment that fails the SEMI F47 immunity require-ment. SEMI F47 is currently going through its five-year revision and update cycle.

All three standards specify voltage sags with certain depths and durations for the

equipment under test (EUT). For example, a specification may state 70% of nominal for 500 milliseconds. The percentage is the amount of voltage remaining, not the amount that is missing. Each standard specifies pass-fail criteria for EUT when a voltage sag is applied; the IEC standards have a range of pass-fail criteria, but the SEMI F47 standard is more explicit (Figure 2).

Three-phase testingFor three-phase EUT, the sags are applied between each pair of power conductors, one pair at a time. If there is a neutral conduc-tor, this implies that there are six different sags at each depth-duration pair: three differ-ent phase-to-phase sags and three different phase-to-neutral sags. If there is no neu-tral conductor, there are just three different phase-to-phase sags at each depth-duration pair in the standard.

Note that IEC 61000-4-11 and 61000-4-34 specifically forbid creating phase-to-phase sags by sagging two phase-to-neutral volt-ages simultaneously—an approach that is permitted in SEMI F47. Instead, you must create phase shifts during your phase-to-phase sags—something that sag generators designed for these standards do automatically (Figure 3). Typical suppliers of compliant sag genera-tors include Keytek (www.keytek.com), Pow-er Standards Lab (PSL, www.powerstandards.com), and Schaffner (www.schaffner.com).

Test equipment requiredA voltage sag generator is test equipment that is inserted between the AC mains and the EUT. It generates voltage sags of any required depth and duration. Some, like the PSL Industrial Power Corruptor, include pre-programmed sags for all of the IEC, SEMI, or MIL standards.

Because a common EUT failure mecha-nism is a blown fuse or circuit breaker during the current inrush after a voltage sag, the sag generator must be specified for delivering large peak currents—typically in the hun-dreds of amps. This peak current requirement in the IEC standards means that electronic amplifier AC sources generally can only be used for precompliance testing, not for certi-fication (Figure 4).

The portability of sag generators is a key consideration. It is often impossible to bring larger room-sized industrial equipment to a test lab. Instead, the test lab must travel to the equipment. In general, the largest por-table sag generators can handle no more than 200 amps per phase at 480 volts (Figure 5). Some of the standards, such as SEMI F47, offer specific advice about how to test EUT that require more than 200 amps (usually by breaking them down into subsystems).

0.01 0.02 0.1 1 10 100

Area included in specification0.05 to 1 second

Duration of voltage sag in seconds

Equi

pmen

t nom

inal

vol

tage

(%)

100

90

80

70

60

50

40

30

20

10

0

2. Playing through. A typical example of a voltage sag ride-through curve compared with the SEMI F47 specification commonly used in the semiconductor industry. Source: Power Standard Labs

α

Θ

L2

L3

L1100%

100%

100%

100%

100%

1–P

P

30°

U L3–L

1

U L1–N

Notes: P = the percent phase-to-phase dip, expressed as a fraction of the nominal phase-to-phase voltage.UL1–N = the voltage from L1 to neutral (if a neutral conductor exists), expressed as a fraction of the nominal phase-to-neutral voltage.UL3–L1 = the voltage from L3 to L1, expressed as afraction of the nominal phase-to-phase voltage.

3. One phase at a time. The IEC stan-dards require phase shifting during sags on three-phase systems, but sags on all three phases simultaneously are not required. Source: Power Standard Labs

4. Portable power. Portable voltage sag generators like this Industrial Power Corruptor from Power Standards Lab handle hundreds of amps at three-phase voltages while remain-ing portable. Built-in standards help speed up testing; built-in digital oscilloscopes help the test engineer diagnose equipment problems. Courtesy: Power Standard Labs

POWER | January 200858

POWER QUALITY

Many conformance certification labs sub-contract voltage sag testing to labs that have engineers with the training and experience both to perform sag testing and to help di-agnose EUT failures. This is an especially attractive approach when certifying large, industrial loads.

For testing smaller commercial and indus-trial loads, many labs rent a voltage sag genera-tor from PSL or another supplier. Such a rental often comes complete with over-the-phone engineering support from an experienced sag testing engineer. This can be the best way to get started on voltage sag immunity testing.

A different kind of testingIn contrast to most other emissions and im-munity testing, votage sag testing requires the engineer to control and manipulate all of the power flowing into the EUT. For smaller devices such as personal computers, this is not a great challenge. But for larger indus-trial equipment, perhaps rated at 480 volts three-phase at 200 amps per phase, with an expected inrush current of 600 amps or more, the test engineer must be prepared for serious performance and safety challenges.

Certain software, such as the sag immunity testing software from PSL, comes with exten-sive safety checklists. Some of the checklist items are obvious (Who on the test team is trained in CPR? Where is the closest fire extin-guisher?), but some are less obvious (How do we get access to at least two upstream circuit breakers? Where is the closest trash can?).

Common failure mechanismsThe most common failure mechanism is lack of energy. This can manifest itself in some-thing as simple as insufficient voltage to keep a critical relay or contactor energized or something as complex as an electronic sensor with a failing power supply giving an incor-rect reading, which would cause EUT soft-ware to react inappropriately (Figure 6).

The second most common failure mecha-nism, surprisingly, occurs just after the sag has finished. In such cases, all of the bulk

6. Anatomy of voltage sag. To test a new device, a voltage sag is introduced in the power source (a). The waveform, which was about 40 amps peak before the sag in this ex-ample, then increases to 450 amps peak after the voltage sag (b). The same current, this time expressed as an RMS value, is shown. The next graph shows the same current, this time as an RMS value. Before the sag, it was about 23 amps RMS (this equipment was rated at 30 amps), but after the sag the current increased to 175 amps RMS. This behavior is not unusual (c). The fi-nal graph shows the output of a DC supply during this sag (d). Courtesy: Power Standard Labs

5. Potential for problems. The voltage sag test engineer will insert a sag generator between the AC source and the equipment being tested. Often, high currents (200 amps) and high voltages (480 volts three-phase) must be handled. Courtesy: Power Standard Labs

a.

b.

c.

d.

January 2008 | POWER 59

POWER QUALITY

capacitors inside the EUT recharge at once, causing a large increase in AC mains current. This increase can trip circuit breakers, open fuses, and even destroy solid-state rectifi-ers. Most design engineers correctly protect against this inrush current during power cy-cling, but many do not consider the similar ef-fects of voltage sags. Be careful when the test procedure is developed; if you use a sag gen-erator that lacks sufficient current capability it will incorrectly pass the equipment if there is insufficient current available to blow a fuse or trip a circuit breaker in a half-cycle.

Another common EUT failure mechanism occurs when a sensor detects the voltage sag and decides to shut down the EUT. In a straightforward example, a three-phase EUT might have a phase-rotation relay that incor-rectly interprets an unbalanced voltage sag as a phase reversal and therefore shuts down the EUT. A more atypical example would be if you had an airflow sensor mounted near a fan, it detected that the fan had slowed down momentarily, and the equipment software misinterpreted the message from this sensor as indicating that the EUT cooling system had failed. In this case, a software fan failure signal delay is the solution to improve sag immunity.

Another common EUT failure mechanism

involves an uncommon sequence of events. For example, in one case, a voltage sag was applied to the EUT and its main contactor opened with a bang. But further investigation revealed that a small relay, wired in series with the main contactor coil, actually opened because it received an open relay contact from a stray water sensor. That sensor, in turn, opened because its small 24-VDC sup-ply output dropped to 18 V during the sag. The solution was an inexpensive bulk capaci-tor across the 24-VDC supply.

Many other failure mechanisms can take place during voltage sags. The question to the test engineer will always be: How do we fix this problem? Usually, there is a simple, low-cost fix once the problem is identified.

Protect your equipmentThere is no one best place to locate a protec-tive device for all your plant equipment. An equipment protection program should begin with identifying specific equipment items that are sensitive to voltage sags, either through hard experience or with the support of the manufacturer. The ubiquitous UPS may not provide enough of the right protection.

However, there are areas where voltage sags have a history of interfering with plant operations by affecting programmable logic

controllers as well as relays and contactors in sensitive equipment. The best approach to handling those problems is to specify new equipment according to a particular voltage ride-through specification, such as SEMI F47.

If you have recently upgraded to adjust-able-speed drives (ASDs) in your plant, you are in luck. ASDs can ride through voltage sags because of the inertia of the motor and the connected load. Some ASD manufactur-ers offer an optional voltage sag ride-through feature.

Very short sags can be tolerated with fer-roresonant transformers, magnetic synthesiz-ers, or active series compensators. Others have employed static transfer switches and fast transfer switches that can operate within two cycles to protect overly sensitive loads.

At PSL, we believe that only in extreme cas-es should devices that eliminate voltage sags on the AC circuit be considered because this is the most expensive possible solution. How-ever, the final selection of a solution requires weighing the cost of equipment and produc-tion losses against the cost of protection. ■

—Andreas Eberhard (aeberhard@powerstandards.com) is

vice president of technical services for Power Standard Labs.

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www.powermag.com POWER | January 200860

MANAGEMENT

Despite all the hype over the past few years about the potential devastation caused by large-scale baby boomer

retirements, recent studies say that age is responsible for only 15% of U.S. workforce attrition. According to the Department of La-bor, in 2006 retirements shrunk headcount by a mere 4.4%.

But here’s another statistic that should give utility executives pause: Last year, “quits” rose to 19.4%–up one percentage point from 2005 and the highest rate in many years.

In other words, if you’re focusing on re-tirements, you’re ignoring nearly 80% of the employee loss problem. But you’re not alone. Surveys report that only one in eight compa-nies has a goal of addressing nonretirement attrition.

Should organizations pay less attention to aging workforce issues and more to the causes of nonretirement departures? Not necessarily. Why? Because every industrial organization has unique characteristics and needs.

Management by fad That uniqueness, however, can open the door to unusual, unworkable, and expensive solu-tions. Over the past two decades, fad after fad has infected the business world. Con-cepts such as large-scale downsizing, Y2K, Total Quality Management, ISO 2000, Qual-ity Circles, and e-business have swept across the organizational landscape. Sometimes these movements brought necessary changes in some sectors. But few found broad interest and long-term use.

Remember the counterintuitive efforts of some bricks-and-mortar stalwarts to set up e-business units during the 1990s (exempli-fied by Time Warner letting itself be acquired

Workforce analysis: Replacing management by fad with management certainty The biggest problem facing industrial managers is ensuring that they’ll contin-

ue to have a skilled workforce. With so many people nearing retirement, organizational skills are at risk, which poses a direct threat to operations. Many companies are making big investments to capture the unique knowl-edge and experience of graybeards before they move on. But that is just one aspect of a far more complex issue.

By Brad Kamph, Interliance Consulting Inc.

Will your plant have qualified staff to fill all skilled jobs five years from now? Courtesy: Progress Energy

January 2008 | POWER 61

MANAGEMENT

by AOL), the billions spent to inoculate IT systems against an imaginary Y2K bug, and the reverence still being paid to the manage-ment techniques popular in the high-flying Enron days? In many cases, unproven man-agement strategies and methods were imple-mented unnecessarily. Sometimes they only wasted time and money. In other cases, they wreaked havoc on firms that had been very successful.

For another example more familiar to power engineers, let’s briefly examine the consequences of downsizing by electric utili-ties. Turbine generator maintenance used to be done by large in-house crews with access to huge in-plant parts and equipment invento-ries. A 1,000-MW plant may have had a full-time major maintenance staff of 75 to 100, many with decades of overhaul experience under their toolbelts. Day-to-day mainte-nance was carried out by another team of 25 to 35 people. With such personnel resources on hand, outage planners had the luxury of long lead times and slow budgeting. Man-agement could predict easily and plan with certainty.

Outsourcing, prompted by Wall Street’s closer attention to utilities’ quarterly re-sults, radically altered maintenance and outage planning and execution. Those big in-house crews are now gone, replaced by just enough people to oversee the work of outsourcing contractors. Inventories have shrunk, too. As a result, utilities and plants now operate in thrall to productivity, domi-nated by short-term planning. Long-term projects, such as vital regional transmission upgrades, are rarely given the priority they deserve. The new corporate culture doesn’t quantify the effects of employee dissatisfac-tion, which may be why more experienced hands are quitting. No one likes work that isn’t fun anymore.

The bottom line is that management by fad just doesn’t work. Lean manufacturing and Six Sigma techniques may work for Gen-eral Electric, but not for smaller firms with limited resources.

Bringing certainty to managementEngineers know that you can’t control what you can’t measure. Developing future busi-ness strategies is pointless without an ac-curate assessment of the current business environment. Understanding the issues is especially critical to forward-thinking work-force management. Here are some questions that any utility or plant manager should be asking—and be able to answer:

■ How deep is my organization’s knowl-edge, and where will wholesale employee retirements create gaps in it?

■ Is my firm capturing the knowledge of senior employees long before they give notice? If so, how? Am I confident that the processes in place are capturing and transferring the right kind of knowledge?

■ Which metrics are being used to gauge the capability of my workforce?

■ Are my organization’s business processes modern and adaptable to changes in busi-ness climate?

■ What kind of personnel should I be look-ing to hire?

■ Are company training programs instill-ing the skills needed to improve business performance?

These questions can be answered by a workforce analysis. It helps organizations identify and quantify existing workforce challenges, forecast future workforce needs, and correlate them to business needs.

A workforce analysis leverages strategic and tactical tools for isolating the existing skills of an organization and measuring the depth of knowledge within it. The analysis then relates specific skills to the business rea-sons for each performance requirement of a job position. A workforce analysis also pro-vides the following information:

■ The strengths and weaknesses of a work-force.

■ Trends in attrition numbers, and their im-pact on mission-critical business skills.

■ Key areas in need of training, process im-provement, and knowledge capture.

■ The depth of knowledge within each job class, and the importance of each task per-formed by workers to achieving business goals.

■ The organizational learning rate—a mea-sure of a firm’s ability to boost its produc-tivity through experience and to transfer knowledge between locations.

■ A map of the strategic skills and knowl-edge gaps that have the biggest impact on accomplishing the organization’s mission.

A workforce analysis delivers exactly what management needs to act with certainty and precision.

Here’s the first of three examples. At one company, an analysis that correlated the company’s skill levels to its attrition rate concluded that if nothing were done to reduce attrition, skilled workers would be unavailable to perform 63% of employee tasks within five years. In this case, the rate of skills attrition outstripped that of retire-ments. Interliance Consulting pinpointed the nature of the problem, identified the most-endangered skills, and delivered to

management a tailored program for solving the problem.

At a second company, workforce analysis revealed a connection between the organiza-tion’s learning rate and loss of skills. It found that high attrition rates in certain departments would reduce skill levels within those depart-ments by 31% over five years at the current learning rate.

At a third firm, an electric utility, the chal-lenge was worker uncertainty. Through in-terviews, the workforce analysis found that the average O&M employee was less than 50% certain of his or her ability to perform all tasks required by the position. Interliance took this workforce analysis one step further. After breaking down employee uncertainty by position, the consultant delivered a report containing the following information:

■ The relative levels of certainty for every plant department and job description.

■ How those certainty levels would change over time.

■ Which skills were most vulnerable to loss.

■ The department needing the most atten-tion.

Those results were then correlated with statistics on the frequency and location of the reported problem. The exercise enabled Interliance to suggest changes in the utility’s knowledge capture, skills development, and process improvement initiatives.

Workforce analysis to the rescueThe product of a workforce analysis is a business case that quantifies the value of knowledge and skills and the cost of losing them. Some consultants are paid hundreds of thousands of dollars for vaguely worded and therefore unworkable “strategic solutions” to general problems involving knowledge cap-ture, training, or business processes. By con-trast, a workforce analysis delivers specific proposals and rigorous analyses. In many cases, implementing the suggested plans has saved companies millions over time.

Another big plus of workforce analysis: It doesn’t take an eternity. Some consultants spend years dissecting the woes of a single production line, racking up thousands of bill-able hours in the process. By comparison, a typical workforce analysis costs much less because it takes only about six weeks from start to finish. ■—Brad Kamph (bkamph@interliance.com) is president of Interliance Consulting Inc.,

a 20-year-old developer of workforce, knowledge management, process opti-

mization, and performance measurement strategies for energy companies.

www.powermag.com POWER | January 200862

NEW PRODUCTS TO POWER YOUR BUSINESS

New thermal imager measures at long distances Wahl Instruments Inc. has added a long-distance model to its line of Wahl Heat Spy thermal imaging cameras. The model HSI3003 offers narrow-angle 9.1° x 6.8° field of view optics, which enables detection and temperature measurement of small objects over long distances. This affordable thermal imager is light, compact, easy to operate, and designed for hand-held

use. It also features a tripod mount for remote use. The camera is fully radiometric and measures the temperature of every pixel. Easy Report software

allows the user to easily insert multiple images (with data) taken during a site survey to produce an inspection report. The imager features a 160 x 120 pixel, uncooled microbolometer array, capable of displaying high-resolution, real-time, thermal images on a bright 3.5-inch color LCD display with LED backlight.

Users can select from among four color palettes. The instrument has a temperature range of 32F to 482F and a trigger-activated, Class II laser that precisely identifies the problem hot spot shown on the marked center of the display. Two measurement cursors, movable anywhere in the image, provide temperature readings at each cursor location and indicate real-time differential temperature measure-ment between the two points anywhere along the temperature range. High-quality images can be captured and manipulated online, or problems can be resolved on the spot. (www.palmerwahl.com)

High-speed megapixel video camera Photron Inc., a global high-speed imaging system and image analysis software supplier, has released Phase II of the ultra-light-sensitive high-speed imager, the Fast-cam SA1. The high-speed CMOS sensor technology in the next-generation Fastcam SA1 delivers up to 5,400 frames per second (fps) at full megapixel (1,024 x 1,024) reso-lution and an unequalled 675,000 fps at reduced resolu-tion. With true 12-bit resolution for extraordinary color fidelity, microsecond global shuttering, and inter-frame timing, the improved imager is also DC powered and fea-tures both SDI and RS-170 video outputs for easy inte-gration. The camera has a user-controlled variable region of interest and also supports IRIG/GPS when precision time stamping and synchronization are required.

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An optional particle image velocimetry facility is available to study the flow of gas in a wind-tunnel environment or to analyze flow in fluids, such as pump cavitation. (www.photron.com)

Get accurate measurements in low-flow-rate applicationsThe Extended Linearity (EL) 500 Series of electromagnetic flow meters from Flow Technology Inc. are available in line sizes from 1⁄8 to ¾ inch and represent the state of the art for accurate low-flow-rate measurement in a wide range of applications. The EL 500 Series creates a unique electromagnetic field profile, ensuring accuracy not only in turbulent flow but also during the transitional and laminar flow regimes.

These compact meters provide extended linearity and a wide measurement range of up to 1,000:1 without the aid of linearization software. The EL 500 has a bidirectional flow capabil-ity with no moving parts and no pressure drop. The meters cover –4F to 320F.

These meters base their operation on the Faraday Principle, by which a conductor crossing a magnetic field generates a potential. The resultant potential is directly proportional to the flow velocity. Connections can be supplied in Hastelloy C or titanium. The standard liner mate-rial is PTFE. The flow meter’s enclosure is stainless steel.

Electronics available for the EL 500 series consist of a base transmitter with optional panel-mounted display as well as a multiple-output converter with an integral display. Electronics can be mounted directly on the flow meter or remotely. When the electronics are remotely mounted the flow meter meets Ingress Protection (IP) Standard 68, making it suitable for permanent immersion in water up to a depth of 5 feet. (www.ftimeters.com)

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Inclusion in New Products does not imply endorsement by POWER magazine.

Wide-temperature-range wireless data logger TandD Corp.’s RTR-52Pt wireless data logger uses industry standard three-wire Pt-100 RTD (resistance tempera-ture detector) sensors, available from many sources. With a temperature measurement range from –328F to +1,100F, the RTR-52Pt is ideal for cryogenic applications, including liquid NO2. In addition, it has an IP-64 water resistance rating.

The RTR-52Pt is compact, portable, and battery operated. Sensors are attached using a standard three-wire screw terminal block. The unit features a large liquid crystal display for reading current values and the device status. The RTR-52Pt can store 8,000 readings in either one-time or endless recording mode.

This new model is compatible with any TandD RTR-5x Series of wireless data collectors. (www.tandd.com)

Compact SCADA system RTU features open programming Semaphore, a CSE Global company, has intro-duced its Kingfisher G30 compact remote ter-minal unit, which features open programming and many advanced features for SCADA sys-tem applications. The G30 RTU also extends the full capabilities of Semaphore’s Kingfisher PLUS+ product line to small SCADA system ap-plications requiring up to 32 I/O points. Like Kingfisher PLUS+, the G30 RTU allows open programming in all five languages specified by IEC 61131-3 and supports IEC 61499. An extensive library of function blocks that in-clude applications such as AGA flow calcula-tions is also provided.

The Kingfisher G30 RTU introduces ad-vanced capabilities normally found only in much larger products into a compact RTU that is cost-effective for small installations. The G30 RTU has been specifically designed to meet the needs of customers with sig-nificantly increasing demands for processing power, data storage, and communications ca-pabilities.

Integral communications include Ethernet, USB 2.0, and an on-board module that pro-vides flexible communications options.

By employing an ARM 7 processor on an in-telligent I/O module, the Kingfisher G30 RTU can process inputs and outputs on a 1-ms interval with full sequence-of-events moni-toring. It also provides high-resolution input acquisition, failsafe output modes, high-speed counting, and pulse generation.

Unlike the “brick” style products in its class, the Kingfisher G30 RTU uses configu-rable modules for communications, I/O, and AC or DC power. The modules provide users with considerable flexibility in meeting ap-plications requirements and enable future up-grades. (www.cse-semaphore.com)

New IR flammable and CO2 gas sensor detects hazardsThe Xgard IR from Crowcon is a new, low-cost IR flammable gas and CO2 sensor designed for use in fixed-point detection systems where conventional detectors can prove unreliable or suffer from in-terference or damage.

Conventional flammable gas de-tectors based on catalytic pellis-tors are susceptible to poisoning in some industrial atmospheres. This can make their readings un-reliable and even destroy the sen-sor altogether. The new Xgard IR is totally immune to poisoning and will reliably warn of gas hazards in environments that are unsuitable for other sensor types. Infrared sensing has other benefits too. Unlike catalytic pellis-tors, IR sensors will fail to safety, detect flammable gas in inert backgrounds, and are not damaged by high gas concentrations.

This new IR sensor can be specified with either of two types of enclosure: polyester-coated aluminum or 316 SS for maximum corrosion resistance in extreme environments. The sensor, which has a life expectancy of over five years, is a simple plug-in module that makes replacement quick and easy. (www.crowcon.com/usa)

65January 2008 | POWER www.powermag.com

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(360) 260-0979 l (360) 253-5292www.powerindustrycareers.com

dom.com

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Energy sources.We are Dominion. As one of the nation’s leadingenergy companies with over 16,800 employees and$45.54 billion in assets, we do more than deliver theenergy that meets the demands of life. We alsodevelop and maximize the potential of our mostexciting energy sources——our people.

Mechanical Engineer Somerset, MAUse your knowledge base of electric powerproduction systems and processes to support theoperation and maintenance of a coal-fired powerplant.

We are seeking a mid- to senior-level engineer toperform a wide variety of mechanical projects,O&M support, and assessments. Will obtain projectrequirements, engineering, costs, schedules, RFPs,construction, startup, and documentation/reporting.O&M experience will include carrying outequipment/system assessments, inspections, androot-cause analysis.

Seeking a highly motivated self-starter with a BS inengineering, 5-15 years of related experience inpower generation, and strong communication,computer, and organizational skills. PE licenserequired.

Dominion offers competitive salaries and a widearray of employee benefits. To apply for either ofthese opportunities, please visit the “Career” sectionof our website at www.dom.com/jobs/index.jspDominion is committed to diversity in itsworkforce. EOE, M/F/D/V.

www.powermag.com POWER | January 200866

Classifi ed AdvertisingMyla Dixon

Phone: 832-242-1969 Ext. 311 Fax: 832-251-8963mylad@powermag.com

January 2008 | POWER www.powermag.com 67

POWER PLANT BUYERS’ MART

READER SERVICE NUMBER 206 READER SERVICE NUMBER 207

POWEREQUIPMENT CO.

444 Carpenter Avenue, Wheeling, IL 60090

wabash

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847-541-5600 FAX: 847-541-1279WEB SITE: www.wabashpower.com

FOR SALE/RENT

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Need a Thorough Mix?Ash, coal, sludges, what do You need to mix?

Get a thorough mix with:Pugmill Systems, Inc.

P.O. Box 60Columbia, TN 38402 USA

ph: 931/388-0626 fax: 931/380-0319www.pugmillsystems.com

READER SERVICE NUMBER 203

Norm Harty - The First and Last Word in Professional Dynamiting,serving you since 1964. We have pioneered, perfected and proven the methods of explosive cleaning the worst of s\lag or ash out in a matter of hours—in all boiler areas. We specialize in Electric Utility work and have over 4000 jobs to our credit. Call the NUMBER ONE COMPANY for the quickest response and most effi cient job for your emergency needs and scheduled outages.

N.B. Harty General Contractors, Inc.Phone: 573-624-4645 or 573-624-4588 ● Fax: 573-624-4589E-mail: norm@nbharty.com ● www.nbharty.com

READER SERVICE NUMBER 202READER SERVICE NUMBER 200

George H. BodmanPres. / Technical Advisor

Offi ce 1-800-286-6069 Offi ce (281) 359-4006PO Box 5758 E-mail: blrclgdr@aol.comKingwood, TX 77325-5758 Fax (281) 359-4225

GEORGE H. BODMAN, INC.Chemical cleaning advisory services for

boilers and balance of plant systems

BoilerCleaningDoctor.com

READER SERVICE NUMBER 201

NEED CABLE? FROM STOCKCopper Power to 69kv; Bare ACSR & AAC Conductor;

Underground UD-P & URD, PILC-AEIC; Interlock Armor to 35kv; Copper Instrumentation & Control; Thermocouple

BASIC WIRE & CABLEFax (773) 539-3500 Ph. (800) 227-4292

E-Mail: basicwire@basicwire.comWEB SITE: www.basicwire.com

www.powermag.com POWER | January 200868 www.powermag.com POWER | January 200868

READER SERVICE NUMBER 209

READER SERVICE NUMBER 208

READER SERVICE NUMBER 214

STGU’s - 15 MW GE condensing 850#steam pressure 3/60/13,800 volts -

GTGU’s - 20 MW Brown Boveri oil fi red “cheap”

BOILERS - 200,000#/HR Combustion Engineering package - 600# steam pressure - gas fi red

- 25,000#/HR ABCO - 150# steam pressure -natural gas and propane fi red

We buy and sell transformers, boilers, steam turbine generator units, gas turbine generator

units, diesel engine generator units, etc.

INTERNATIONAL POWER MACHINERY CO.50 Public Square - Terminal Tower, Suite 834

Cleveland, OH 44113 U.S.A.PH 216-621-9514/FAX 216-621-9515

Email: kernx06@sbcglobal.net Web: www.intlpwr.comREADER SERVICE NUMBER 213

POWER PLANT BUYERS’ MART

Demolition of Electric Power Generating Plant and Paper Mill in Garfi eld, NJ.

4 Steam Turbine Generators (GE & Westing-house) and all related equipment: transformers, pumps, panels, remaining switchgear, 200+ elec motors (20 to 500+ HP, etc, etc. Walk-thru, make an offer sale, Jan 30th.

RSVP jacss@rcn.comREADER SERVICE NUMBER 211

CONDENSER OR GENERATOR AIR COOLER TUBE PLUGSTHE CONKLIN SHERMAN COMPANY, INC.

Easy to install, saves time and money.ADJUSTABLE PLUGS-all rubber with brass insert. Expand it,

install it, reverse action for tight fi t. PUSH PULL PLUGS-are all rubber, simply push it in.

Sizes 0.530 O.D. to 2.035 O.D.Tel: (203) 881-0190 • Fax:(203)881-0178

E-mail: Conklin59@aol.com • www.conklin-sherman.com

OVER ONE MILLION PLUGS SOLDREADER SERVICE NUMBER 210

READER SERVICE NUMBER 212

August 2007 | POWER www.powermag.com 69January 2008 | POWER www.powermag.com 69August 2007 | POWER www.powermag.com 69January 2008 | POWER www.powermag.com 69

POWER PLANT BUYERS’ MART

• <6ppm NOx– With CRI Catalyst/Shell DeNOx

components

• FIeld Installation– On package boilers to 250,000 lb/hr

• Simple Operation– No special facilities, permits, controls

or modifications required

• Low Pressure Drop– 2" WC means no fan changes

Call 1-800-227-19661-510-490-7100

Or Visit: www.nationwideboiler.com

CataStak™

Brings Ultra Low NOx to package boilers

RentalsLeasesSales

San Francisco • Baton Rouge • Birmingham • Calgary • Charlotte • Chicago • ClevelandHamilton, Ont • Houston • Philadelphia • Seattle

READER SERVICE NUMBER 218

Boiler Cleaning ProfessionalsExplosive Deslagging Services • Camera Assisted On-line Blasting • Detonating Cord and OverheadHazard Blasting • Introducing On-line Video Inspection/Recording of Bundle, Pendant and Wall DepositsGrit-Blasting • Electrostatic Precipitator Field Cleaning • UT and Boiler/Vessel Overlay Preparation• On-line Radiant Recovery with “Shatter Blast” Bead Impact Deslagging“Big Water” High Pressure Washing • Air Pre-heater Baskets, Furnace + Boiler Washing• Heat Exchanger/Condenser Hydro-Laze, Pipeline CleaningVacuum Services, Wet + Dry • Fly Ash, Sludges, Silo + Vessel EvacuationNumber One In Safety and Compliance. Privately Owned and Operated 24/7 Emergency Response From Many US Locations

800-866-6247 • www.naisinc.come-mail: naisinc@naisinc.com

READER SERVICE NUMBER 217

Combustion, Energy and

Steam Specialists Ltd.

Surplus Power Plant

Specialists in the Valuation, Marketing, Sourcing, and

Relocation of Surplus Power Plant & Auxiliary Equipment

Tel: +44 (0)1856 851177 Fax: +44 (0)1856 851199E.mail: enquiries@cess.co.uk Web: www.cess.co.uk

READER SERVICE NUMBER 216READER SERVICE NUMBER 215

CFB Boiler • Steaming Capacity: 700,000 lb/hr of superheated steam • Pressure: 1250 psig • Temperature: 1000 °F at main steam stop outlet valve • Feedstock: PRB Coal Fabrication is partially complete. Reduce your project schedule by purchasing the rights to this CFB Boiler.

For complete details please contact:Keith Schick, 720-945-0641

For Sale

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READER SERVICE NUMBER 219

READER SERVICE NUMBER 222

POWERClassifi ed {klas-uh-fahyd},adj. The designated part of a publication that contains advertisements belonging to a specifi c group or category.

Defi ne youradvertising in

POWER• Recruit quality professionals

• Buy and sell products and services

• Showcase your products

• List RFPs and Renewable Supply Credits

To designate your space,contact Myla Dixon

832-242-1969mylad@powermag.com

www.powermag.com POWER | January 200870

PRODUCT Showcase

READER SERVICE NUMBER 223

READER SERVICE NUMBER 220 READER SERVICE NUMBER 221

ADVERTISERS’ INDEXEnter reader service numbers on the FREE Product Information Source card in this issue.

Page

ReaderServiceNumber

CLASSIFIED ADVERTISINGPages 65–70. To place a classified ad, contact:

Myla Dixon, POWER magazine, 832-242-1969, mylad@tradefairgroup.com.

January 2008 | POWER www.powermag.com 71

Africa Power Electricity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44 www.terrapinn.com/2008/powerza

AIG . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35. . . . . . . . 22 www.aig.com

ARA Asia Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 www.coalgenchina.com

Ashross . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15. . . . . . . . 13 www.ashross.com

Babcock & Wilcox . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Cover 4. . . . . . . . . 3 www.babcock.com

Babcock Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25. . . . . . . . 19 www.babcockpower.com

Benetech . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21. . . . . . . . 17 www.benetechusa.com

Cablesafe Hooks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10. . . . . . . . . 8 www.cablesafe.com

CD-Adapco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16. . . . . . . . 15 www.cd-adapco.com

Columbus McKinnon . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8. . . . . . . . . 6 www.cmindustrial.com

Conoco Lubricants. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Cover 2. . . . . . . . . 1 www.lubes.conoco.com

Emerson/Rosemount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27. . . . . . . . 20 www.raihome.com

ExxonMobil. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7. . . . . . . . . 5 www.exxonmobil.com

HACH . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13. . . . . . . . 10 www.hach.com/power

Hitachi Power Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Cover 3. . . . . . . . . 2 www.hitachi.com

Magnetrol . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11. . . . . . . . . 9 www.magnetrol.com

Mitsubishi Power Systems, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . .18-19. . . . . . . . 16 www.mpshq.com

Orion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23. . . . . . . . 18 www.orioninstruments.com

Power Systems Mfg. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5. . . . . . . . . 4 www.powermfg.com

Roberts & Schaeffer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9. . . . . . . . . 7 www.r-s.com

Schmidt Industries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14. . . . . . . . 12 E-mail: schmidtind@aol.com

Siemens . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31. . . . . . . . 21 www.siemens.com/powergeneration

Turbine Energy Solutions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15. . . . . . . . 14 E-mail: sales@turbineenergysolutions.com

Zolo Technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14. . . . . . . . 11 www.zolotech.com

www.powermag.com POWER | January 200872

COMMENTARY

U.S. nuclear power’s time has come—againBy Bob Percopo

In the U.S. today, there are continual discussions about en-ergy independence, energy security, and ways to slow climate change. But meeting the nation’s projected 40% increase in

electricity demand by 2030, while reducing overall power plant CO2 emissions, will require much more than talk.

During the 1990s, American utilities increased their gas-fired generating capacity because they believed that gas would always be cheap and plentiful. Neither assumption proved true. At this year’s G-8 Summit of the world’s economic and military powers, President Bush committed the U.S. to develop a voluntary car-bon abatement program, so developing new coal- and gas-fueled plants will be challenging. On one hand, the U.S. is the Saudi Arabia of coal, with more than 250 years of reserves; on the other hand, burning coal releases twice as much CO2 as burning natural gas. Meanwhile, natural gas continues to become more expensive and scarce in America.

Oil and gas imports by industrialized countries have weakened their economies due to the increasing prices of those imports. CO2 abatement will create a greater drain on the West and Japan, since they are the ones preparing to pay for it. Capturing and sequestering CO2 will increase the capital cost of a clean fossil-fueled plant by 25% to 50%. China—about to become the world’s largest carbon emitter—has determined that carbon abatement is an issue for wealthy countries, and therefore not its priority. In the U.S., conventional coal plants, which fueled 49% of electric-ity generation in 2006, produced 2,121 million metric tons of CO2 that year. Natural gas, which fueled 20% of energy generation, produced 1,169 million metric tons. In stark contrast, nuclear generation has no carbon footprint.

Land and cost advantages, tooThe average nuclear plant of 1,000 MW requires 2.3 square miles of space. According to the Nuclear Energy Institute, a wind farm of comparable capacity, which also produces zero CO2, would oc-cupy an area of 235 square miles.

This article is not meant to denigrate renewables, coal, or natural gas—all have a place in the generation mix. But renew-ables’ role will be limited by land requirements and a shortage of dependable resources and suitable sites. Development of fossil-fueled plants will be limited by carbon caps.

Nuclear generation’s operating costs also give it an advantage. If the cost of uranium were to double, the production costs of nuclear plants would increase by only 7%. The doubling of the cost of natural gas has increased the per-kWh cost of gas plants by about 70%. Additionally, uranium is available from stable U.S. allies—most notably Canada and Australia.

U.S. positioned to loseWhile the U.S. ponders the economics of building as many as 30 new nuclear plants, China, India, Russia, Brazil, Bulgaria, Romania, and others are planning and executing aggressive nuclear plant construction programs. Unfortunately, the U.S., Western Europe, and Japan are acting as if they have a choice about increasing nuclear power production. The only country with a different attitude is France, the poster child for success in nuclear power on every front—development, O&M, fuel re-processing, and safety. France gets 80% of its electricity from nuclear reactors.

While the G-8 nations endlessly debate the risks of melt-downs, spent-fuel storage, plutonium proliferation, and terror-ist attacks on nuclear plants, developing economies are rushing to add more reactors or join the nuclear generation club. If its procrastination continues, the West will paint itself into a corner and suffer the costs of energy dependence and carbon sequestration.

Nuclear power is not an immature technology like integrated gasification combined-cycle generation. Over its 40-year history, nuclear generation has improved its efficiency from 50% to more than 90%. Its two major perceived negatives are safety and the need to manage spent fuels. Safety concerns naturally arose after a partial core meltdown at the Chernobyl plant in 1986. But the Chernobyl unit had virtually no containment. Modern reactors are housed in containment vessels, and many new units are designed to withstand a direct hit from a fully fueled aircraft.

With respect to spent fuels, most Americans believe that somewhere there’s an area the size of Texas filled with barrels of oozing radioactive waste. However, all the spent fuel from 40 years of reactor operations in the U.S. would fit in a football field 15 feet deep. If the U.S. were to recycle its nuclear waste, the volume would shrink to that of one end zone 10 feet deep. Compare those numbers to the volume of a single ton of CO2 at sea level (60 feet by 20 feet by 16.3 feet). The average 250-MW coal plant emits 1.7 million metric tons of CO2 every year.

Economics and common sense dictate less debate and more action. Worldwide, there are four reactor manufacturers and only one supplier of specialty steel, and they sell their products on a first-come, first-served basis. Arriving “too late for lunch” will have its consequences for the U.S. ■

—Bob Percopo is executive vice president of AIG Global Marine and Energy (www.aigglobalmarineandenergy.com).

If its procrastination continues, the West will paint itself into a corner and suffer the costs of energy dependence and carbon sequestration.

ONE HITACHI...ONE HITACHI...

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www.hitachi.us/hpsa power.info@hal.hitachi.comHitachi Power Systems America, Ltd. 645 Martinsville Road Basking Ridge, NJ 07920 Tel: 908.605.2800

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We call these tangible renewable energy credits.

Consider biomass as an energy source for electric power production. Energy from biomass is dependable,dispatchable and readily available. In addition, biomass is CO2 neutral and can reduce plant emissions.

Diversify your fuel portfolio and earn renewable energy credits.

Call 1-800-BABCOCK or visit www.babcock.com.

© 2007 The Babcock & Wilcox Company. All rights reserved.CIRCLE 3 ON READER SERVICE CARD