Utility Fax Alert 665

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The future of coal in the U.S. depends on the price and availability of natural gas. There is considerable controversy on this subject. One possibility is that gas will cease to be an option for baseload power generation. The other possibility is the one included in the 2004 EIA forecast which shows gas being the fuel of choice for new power plants built after 2010. However, this is the same group that failed to predict the present high prices.

The rationale for greater use of gas used to be greater production in the U.S. Now that falling production is the consensus forecast the rationale is that we will import LNG from the vast reserves of gas from around the world.

Let's reduce everything to quads (quadrillion Btu). The reserves are 5,000 quads of which the U.S. has only 261 and the former Soviet countries have 2,000. The Middle East reserves are 1,700 quads. The U.S. produces only 19 quads but consumes 23 quads. World gas production is only 100 quads. The U.S. uses 22 quads of coal for power generation. Total world primary energy production is 400 quads of which coal accounts for 100 quads.

Five thousand quads available and only 23 being consumed in the U.S.˜this sounds pretty good. But the U.S. has only four percent of the world's people. If the rest of the world used natural gas at the rate we do now, the present reserves would disappear in nine years. China is building large LNG terminals and will be a big consumer. Canada will be using its gas reserves to extract tar sands. Many countries do not have 300 year coal reserves as does the U.S. They will be competing for gas that is available.

There will be additions to the gas reserves. But how long will it be before the new gas finds are deeper and less productive and therefore more expensive. By the time the gas is liquefied and transported how expensive will it be? This is the question for the long term. But what about the near term? Enough LNG terminals in the U.S. could be up and running by 2010 to provide eight quads of natural gas. However, with the Canadian supply diminishing, U.S. production plummeting and demand for home and industrial uses expanding, this may not provide much for power generation.

The availability of these terminals and the infrastructure to utilize them are far from certain. Siting problems are a major hurdle. Delays are plaguing the projects now in the development stage. It is therefore unlikely that LNG will be a quick fix to the present scarcity problem. The longer term outlook is fraught with more questions than answers. It is therefore surprising to see projects moving into the construction stage where the plan is to provide baseload power generation using natural gas.

There are signs that the mercury proposal could become more stringent. Buffeted by complaints about the mercury proposal from both within and outside the agency, EPA Administrator Michael Leavitt has called for additional analysis. EPA staff members say they have been asked to suggest possible comparative studies for the agency to run, much like the analyses they say they were ordered not to conduct last year. "The process is not complete, nor is the analysis," Leavitt said Monday. "I want it done well, and I want it done right, and I want it done in a way that will maximize the level of (mercury) reductions. Leavitt portrayed the new period of inquiry as part of the "normal process" of rule-making, noting the agency had so far filed only a provisional rule. But veteran regulators say it is unusual to propose a rule first and do extensive comparative studies later, unless new information emerges.

"There is a politicization of the work of the agency that I have not seen before," said Bruce C. Buckheit, who is well known to readers of the Alert. Bruce spearheaded the NSR actions against the wood products industry and then refineries and power plants. He retired in December as director of EPA's Air Enforcement Division, partly because he felt enforcement was stymied. "A political agenda is driving the agency's output, rather than analysis and science," he said.

Neither option presently proposed makes much sense. The central problem is that the cost for removal of mercury is uncertain. The present proposals are based on certain assumptions relative to the cost of removal at various points in time. These assumptions are critical to the worthiness of the rule. If they are wrong then the rule is unworthy. The logical approach is to base the rule on cost and let the removal efficiency be a function of the cost. Under a McIlvaine proposal the utility has the ability to opt out of the requirement at ever increasing costs per pound of mercury not removed. It could opt out and pay $5,000/lb in 2007 but the opt-out price would be $25,000/lb in 2015.

The McIlvaine proposal is achieved using the safety valve allowance provision already in the cap-and-trade version of the bill. The only difference is that the cap is set at five tons immediately and the safety valve price is set low. So the cost of not meeting the target is only a fraction of a mil/kWh. But each year the cost rises. The analysis shows when the cost of not removing mercury exceeds the cost to remove it then utilities will opt to install controls. This alternative proposal would provide great incentive for commercialization of new and better technology at the earliest possible date.

We have included charts to show the impact of rising safety valve allowance costs. You will note that the chart for the typical 300 MW power plant shows that 33 percent removal will occur if the safety valve price is $1,000/lb. The cost impact will be 0.04 mils/kWh.

When this opt-out price rises to $3,000/lb the removal efficiency rises to 44 percent and the cost increases to 0.11 mils/kWh. At an opt-out price of $25,000/lb, 85 percent efficiency would be achieved and the cost would be 0.67 mils/kWh.

These are very modest costs. We could be wrong on the removal percentages but probably by not more than 10 percentage points. In other words, a worst case scenario might only be 75 percent removal when the cost rises to $25,000/lb. We also show in the analysis that the last few percent removed can cost a lot. Once you start adding activated carbon at 30 lbs/MMacf the costs sky rocket and you may only be removing a few more pounds than you did at 10 lbs/MMacf. How many rate payers would choose 90 percent mercury removal for a 10 percent increase in monthly electricity bills when they could have 85 percent with just a one percent increase? The way to proceed is to fix the cost and let the efficiency be the variable.

One of the monitoring alternatives being considered by EPA is what they call better „QAQC". Instead of dictating that CEMS have to be installed by the biggest emitters and that sorbent traps would be allowed for smaller emitters, EPA would not dictate any specific alternative but insist on better validation of the results. McIlvaine applauds this thinking and recommends that this option be more extensively pursued.

Monitoring mercury to the degree of accuracy required for trading ($35,000/lb) is a daunting task. Add to this the fact that EPA has not addressed particulate mercury and suggests just ignoring this quantity. The rationale is that particulate mercury is only three percent of the total. At $35,000/lb the ignored quantity translates into $105,000 for a 300 MW boiler, $1,050,000/yr for a 3,000 MW plant and $105,000,000 for the whole industry. Mercury measurement is money measurement. Could we have an ATM system if it short changed its customers by three percent?

This number may even be larger. Fine particulate emissions from power plants are not measured. McIlvaine believes emissions are much larger than EPA estimates. Furthermore, the quantity of particulate bound mercury may increase due to attempts to capture more. We have been reporting the Sedman theory that mercury capture is a function of acid deposition site area. Condensing SO₄ on to fine particulate is one of the proposed routes for more mercury capture.

The financial audits provide investors some assurance as to claimed profits. We need a professional group which provides assurance that reported mercury emissions are accurate. This should be a holistic approach. It should take into account periodic filter samples to determine particulate mercury. Because of questions about both sorbent traps and CEMS, it may be necessary to operate both and obtain greater insight from review of both numbers. Use of data regarding mercury content of the coal may also prove useful. The audit should conclude that mercury emissions are a certain number plus or minus a certain percent. The emission number for trading purposes should be the highest in the range.

Small mercury emitters may want to reduce audit costs by eliminating redundant measurement. They would then be reporting larger plus or minus variations. If a plant only emits 1 lb/yr a variation of plus or minus 20 percent will only increase allowance payments by $7,000. However, the average 300 MW plant with 100 pounds of mercury emissions can spend quite a bit for monitoring and audits instead of paying an extra $700,000 in allowance payments.

Since audits will often be undertaken for multi-unit plants the financial stakes are high. As in the 3,000 MW example above, the reduction in reported emissions of three percent is worth over $1 million. With stakes this high there will be little reluctance from the utility industry to embrace the audit concept. Let a newly formed association set the protocols. EPA can advise but the industry can be self-policing. In fact, other utilities will find it in their best interest to sue utilities that are under reporting emissions.

The Audit Concept Needs to be Expanded to Other Pollutants

The concept of following precise procedures without regard for the accuracy of the result is what brought down Enron and many other companies. We have some absurd examples in pollutant monitoring. Utilities are ordered to place their opacity monitors in the stack before the scrubbers. The reason is that you cannot measure opacity in the steam plume following a scrubber. Many scrubbers are reducing particulate by 80 percent. Others (with poor mist elimination) are actually adding limestone particles and increasing particulate emissions. Only bureaucratic myopia can result in a decision to put the instrument where it works best rather than where it can provide useful results. Measuring fine particulate is a complex task requiring multiple parallel approaches. This is a perfect area for the audit approach. EPA should give the industry the flexibility on how to determine emissions but insist that whatever method chosen would stand up in court or more specifically the scrutiny of a professional audit.

Does it Make Sense to Differentiate Between Sub-bituminous and Bituminous Plants?

Why did the MACT standard differentiate based on coal type? One answer given by the environmentalists and some EPA people (talking to reporters on condition their names not be used) is that a lobby group from the western U.S. wrote the specific language which was incorporated in the proposed rule.

The technical answer is that activated carbon will not be as effective on sub-bituminous coals. But this is just one technology and is really based on the lack of acid deposition sites. If you add a little PVC in with the coal you will have a cheap high Btu fuel and the chlorine needed for creating the acid deposition sites.

We have also proposed biomass gasification which if introduced as a reburn fuel would reduce NO_x and also supply the chlorine. Various other additives (amended silicates and sodium tetrasulfide) are claimed to be equally effective on mercury removal from sub-bituminous coals as from bituminous.

We believe a real winner would be the chloride pre-scrubber. It can be used with any coal type. It eliminates chloride corrosion in the SO₂ scrubber and reduces the cost of wastewater treatment and gypsum washing. ALSTOM reports on one waste incinerator in Germany where the chloride pre- scrubber removes 80-90 percent of the mercury and in tandem with the downstream SO₂ scrubber removal is as high as 95 percent. So this is a proven technology with lots of installations in Europe.

„Most of Degussa's experience with TMT for mercury removal is with garbage incinerators. However, we also have many coal-fired power plants using TMT as well. The traditional application of TMT has been in treating the blowdown stream in a wastewater treatment system.

The garbage incinerators are typically equipped with an acid scrubber (to take out chlorides as HCl) followed by an "alkaline" scrubber operating in the pH range of 5 to 7. These scrubbers are typically packed towers. One benefit of having two scrubbers is a cleaner gypsum by-product. Another benefit is better mercury removal. Most mercury (perhaps 70% to 80%) is typically removed in the acid scrubber. Oxidized forms of mercury are soluble and form stable chloro complexes in the scrubbing media. Since SO₂ passes through the acid scrubber, the chemical reduction of Hg (II) ion to elemental mercury by the sulfite ion is less likely.

The trend at German plants is to spray dry the blowdown so that there is no wastewater. These plants have decreased the blowdown flow (to lighten the water load on the spray dryer) and increased the salt concentrations in the scrubbing media. Naturally, the mercury concentration in the scrubbing media of both scrubbers increased as well. We believe that this in turn leads to increased stack emissions. Under this operating scenario, plants with continuous emission monitors discovered that they could not meet their emission limits. It was found that TMT directly injected into the scrubbing media of the alkaline scrubber, decreased the gas phase mercury emissions.‰

The conclusion has to be that the cost of mercury removal is likely to be about the same regardless of the coal type. For EPA to micro manage operations and in effect influence the type of coal being burned is astounding. McIlvaine has offered an alternative mercury rule which would protect plants which could not economically remove mercury but is not dependent on unwarranted assumptions about technology.

New Brunswick, Canada will need a new source of power by 2007, and a new coal-fired Belledune plant is being considered. Energy Minister Bruce Fitch said "the government would not move forward on a second plant unless there is strong support in the region."

Nevco Energy Co. needs to raise money from investors to build the $350 million Sevier Power Co. plant in Sigurd, Utah. Earlier this month, the Utah Division of Air Quality invited the public to comment on Nevco's proposed air permit, which would set upper limits for plant emissions. After a Thursday public hearing in Richfield, the comment period ends April 2. Proponents have secured more than enough water rights for the power plant, which would consume about 87 gallons per minute. They still need to secure investor financing and contracts for coal, about 940,000 tons a year, most likely from Utah mines. PacifiCorp is a potential buyer for the plant's generating capacity of 270 MW. The "Circulating Fluidized Bed" plant will use dry cooling to minimize water use.

We have revised Utility Plans to reflect a startup date for the SCR at Detroit Edison Monroe 3 of 2007 (in time for the ozone season) and Monroe 2 for the 2009 ozone season. Construction is slated to start in 2005. Washington Group is the engineer for these units and also was involved with the first two units which are now in operation. The first two SCR systems were supplied by Babcock Power.

Pleasant's Unit 1 at Allegheny Energy has been offline since February 9 due to a generator failure. It is expected to return to service in mid June. Unit 2 of the Hatfield Ferry plant of Allegheny Energy has been offline since November due to a fire which damaged the boiler and turbine. This unit should be back in service by early May.

A bill modeled after the North Carolina law has been introduced in both the House and Senate in Florida. Progress Energy would have to reduce NO_x by 20 percent at its Bartow and Anclote plants. Fifty percent NO_x and SO₂ reductions would be required at the 4-unit Crystal River plant. Progress Energy is supporting the bill but Florida Power & Light (FP&L) is less enthusiastic. It has substantial capital commitments already with additional capacity at its Martin and Manatee plants and a new Turkey Point plant.

The attorney general in North Carolina has asked the federal Environmental Protection Agency (EPA) to force power plants in13 states to cut down on air pollution. Attorney General Roy Cooper says that pollution is harming air quality in North Carolina. Cooper claims the out-of-state polluters are interfering with his state's ability to meet national air quality standards. He says they can't stop pollution from coal-fired plants at the state line, so they have to go to the source.

Cooper says his petition will force the EPA to determine if the out-of-state plants are significantly contributing to North Carolina's difficulty in meeting clean air standards for particulate matter and ozone. The states named in Cooper's petition are Alabama, Georgia, Illinois, Indiana, Kentucky, Maryland, Michigan, Ohio, Pennsylvania, South Carolina, Tennessee, Virginia and West Virginia.

Great Northern has selected a site in McCone County, Montana west of Circle as its preferred alternative to build a 500 MW coal-fired generating plant costing nearly $1 billion. A 60 MW wind power auxiliary unit is included alongside. "Our preference is for Nelson Creek," Jerry Vaninetti, president of Great Northern Power Development of Denver, said Wednesday morning. Kiewit Mining Group of Omaha, Nebraska, is a full partner in the venture.

Santee Cooper will install $100 million in pollution-control devices and pay a $2 million penalty to settle what the Department of Justice viewed as violations of the Clean Air Act.

During an inspection last May, the state Department of Health and Environmental Control (DHEC) found Santee Cooper crews had illegally started construction of a new, long-planned coal-burning unit at its Cross facility. The utility had applied for permits to build the site more than a year earlier, but DHEC hadn't OK'd the project yet.

The agreement filed Tuesday was the product of months of negotiations between Santee Cooper, the Department of Justice, EPA and DHEC. The pollution controls will be in place by 2009 and are expected to cut nitrogen oxide emissions by 70 percent and sulfur dioxide emissions by half. A total of about 67,000 tons of pollutants are expected to be eliminated annually.

The $100 million price tag for the improvements will be tacked onto $1.4 billion the utility plans to spend on capital improvements over the next few years. Santee Cooper will cover most of that sum with bond issues and said no rate increases will be necessary.

As part of the settlement, a $1.2 million fine will be levied by the state and a $700,000 penalty will be exacted by DHEC. It is one of the largest penalties imposed by the agency in years.

Rentech has been proceeding with its work under the Technical Services Agreement with Clean Coal Power Resources Inc. (CCPRI) of Louisville, Kentucky. This is in support of a project which could produce up to 190,000 barrels per day of Fischer-Tropsch liquids from coal in Southern Illinois if all phases are completed. CCPRI, the project developer and owner, intends to implement Rentech's technology to produce ultra-low-sulfur and aromatic fuels from synthesis gas, a mixture of hydrogen and carbon monoxide, made from Southern Illinois coal at its (CCPRI's) proposed $2.5 billion Phase 1 coal-to-electricity and fuels project to be located in Vandalia, Illinois. Phase 1 of this project will entail: the development of a world-class coal mine; the construction of a coal gasification plant to produce clean synthesis gas from the coal to be used to generate power; and the production of approximately 40,000 barrels per day of naphtha and clean diesel fuel using the Rentech GTL Process technology. Rentech recently completed its initial work in support of Phase I of this project and is currently awaiting CCPRI's directive to move to the next segment of Phase I.

The Manistee, Michigan City council has rejected a $2 million community service fee. Tondu is hoping to build a coal-burning power plant in the area but this decision casts doubt on the project's future.

Manistee Saltworks/Tondu Corp. is seeking a special land use permit for the proposed 425 MW Northern Lights coal-fired power plant it wants to construct along Manistee Lake. The request must be approved by the city planning commission, but commissioners could require that Tondu have an agreement with the city council on the community service fee. "If there is no agreement, that would affect our decision," said Roger Yoder, planning commission chairman.

City manager Mitchell Deish said city council members turned down the company's offer Tuesday because it didn't mitigate the negative effect the plant could have on tourism, development, the environment, health and perceptions of the Lake Michigan community. "They felt the amount was inadequate," Deish said.

The ownership of the proposed plant has yet to be determined. If it is privately owned, city taxes on the plant could be as high as $16 million a year, opponents said. If owned by a group of municipalities, it could be exempt from local property taxes. Tondu spokeswoman Deborah Muchmore said a final decision has not been made on the municipal ownership idea. The in-lieu-of-taxes payment offer includes a base of more than $2 million annually, profit sharing of up to $1 million each year and a one-time contribution of $4 million for capital costs related to treating the plant's effluent in the city's wastewater treatment plant. "This is a final offer," Muchmore said of the fee proposal the city rejected.

Fortum Power & Heat has ordered the automation modernization from Metso for its Kauttua CHP (Combined Heat and Power) plant in Finland. Metso Automation's turnkey delivery includes Metso DNA automation system for control and management of the plant's fluidized bed boiler and turbine. The start-up is scheduled for July 2004. In addition to electricity, the Kauttua plant produces steam for the process purposes of Ahlstrom Kauttua and Jujo thermal paper mills, Amcor paper converting mill, and the Kauttua district heating plant.

Ontario to Request Bids for 2,500 MW to Replace Some of Existing Coal-fired Capacity

Ontario is looking at a price tag of up to $40 billion to upgrade the province's aging electricity system, Energy Minister Dwight Duncan said yesterday. "It could well be one of the largest peacetime investments in the history of this country," he said. A financial review has concluded that money-losing OPG's survival is in question.

The provincially owned company produces 70 per cent of the province's power, and Duncan said something has to be done soon to get more power on line before 2006-07, which he calls "crunch" time when demand for electricity will outstrip supply.

Because the Liberal government has promised to close the five coal-fired plants by 2007 and the aging nuclear plants are either down for repairs or acting up on a regular basis, Ontario is faced with a serious power shortage.

Duncan said he could not say whether prices will have to go higher than the 4.7 cents a kilowatt hour for the first 750 kilowatt hours and 5.5 cents for anything after that, effective April 1. The price is being increased slightly from the cap of 4.3 cents per kilowatt hour put on by the former Conservative government. "What I can tell you is this ... if we don't respond prices will go up," the minister told reporters. "Doing nothing is not an option." Duncan said he will spell out where the $30 billion to $40 billion is going to come from when he lays out the government's plans to improve generation some time in the fall.

Tory MPP Garfield Dunlop said it would be irresponsible for the government to close the coal-fired plants in less than three years without knowing what will replace them. "He is trying to keep one of his promises that they made during the election to close the five coal-fired generating plants, but my guess right now is that it won't happen," Dunlop said.

Duncan noted that the province has to remain competitive with such neighboring states as New York and Michigan so that power-hungry Ontario industries can compete. He has said he hasn't ruled out the construction of new nuclear plants, which would take eight to 10 years to produce power, but he promises the government's plan will call for a mixture of generation, so as not to be too dependent on one source.

The government is to release a report on OPG's future from a panel headed by former federal finance minister John Manley. Duncan has refused to say whether the utility will stay in public hands. The Manley report is expected to recommend that the nuclear division of OPG be run as a separate unit from the firm's electricity operations. As well, the panel is likely to say that OPG's head office should move to Niagara Falls from Toronto. Manley will recommend what to do with the refurbishment of the Pickering A nuclear plant, which is three years late and $2 billion to $3 billion over budget. And, Duncan said, "Darlington, which is our newest nuke, is now at the stage in its life where we can expect problems to start with it, according to what the experts have told me."

The Liberal government is under pressure from Atomic Energy of Canada Ltd. to build as many as eight new reactors, but the Liberals are under just as much political pressure from environmentalists to walk away from nuclear technology. "There is no magic bullet," said Duncan, emphasizing that to meet energy demands, Ontario will have to rely on a combination of conservation and generation from many sources, including renewable resources.

The province is about to issue a request for proposals to build 2,500 MW of generating capacity to replace one-third of the power now produced by the coal-fired plants. There is a 580 MW gas-fired plant near Windsor, or about the same as one nuclear reactor, waiting in the wings. "We will (also) be announcing a conservation plan, we have to make a decision on Pickering A units one, two and three, we have to make decision on Bruce A, units one and two, so there are ways of moving (along on new generation)," Duncan said. "At this moment it is not (enough) but we will lay out a plan where I believe we will get to where we have to be in order to achieve our goals," he said.

Duncan said it is important to the environment and to the health of Ontarians that the coal-fired plants are closed, and to that end the province is asking the federal government for $300 million to help defray the cost of building power line connections to Quebec and Manitoba.

Greenhouse gas emissions will cost new Washington power plants in the future under a new law approved by the State Legislature this year. The bill requires new power plants to offset 20 percent of the carbon dioxide they send into the air through mitigation projects. Such projects could include energy conservation projects, forest preservation or converting diesel-powered buses to natural gas. Power producers can either finance the projects on their own or pay someone else to do it at the rate of $1.60 per ton of carbon dioxide produced.

The Shaw Group Inc. was awarded a $170 million contract by PacifiCorp to provide engineering, procurement and construction services (EPC) for the 525 MW combined-cycle natural gas power plant near Mona, Utah. The project, called Currant Creek, is located about 75 miles south of Salt Lake City. In addition to providing EPC services for the Currant Creek project, the company plans to fabricate piping systems and modular components at its nearby fabrication facility in Clearfield, Utah. PacifiCorp will procure the major equipment for the project, which has begun limited construction pending completion of the full air quality permitting process.

Location	Capacity	Developer
Existing Terminals with Expansions
Everett, MA	1.035 Bcfd	Tractebel
Cove Point, MD	1.0 Bcfd	Dominion
Elba Island, GA	1.2 Bcfd	El Paso
Lake Charles, LA	1.2 Bcfd	Southern Union
Approved Terminals
Hackberry, LA	1.5 Bcfd	Sempra Energy
Port Pelican	1.0 Bcfd	Chevron Texaco
Proposed Terminals - FERC
Bahamas	0.84 Bcfd	AES Ocean Express
Bahamas	0.83 Bcfd	Calypso Tractebel
Freeport, TX	1.5 Bcfd	Cheniere/Freeport LNG Dev.
Fall River, MA	0.4 Bcfd	Weaver's Cove Energy
Long Beach, CA	0.7 Bcfd	SES/Mitsubishi
Proposed Terminals - Coast Guard
Gulf of Mexico	0.5 Bcfd	El Paso Global
California Offshore	1.5 Bcfd	BHP Billiton
Louisiana Offshore	1.0 Bcfd	Gulf Landing - Shell
Planned Terminals
Brownsville, TX	N/A	Cheniere LNG Partners
Corpus Christi, TX	2.7 Bcfd	Cheniere LNG Partners
Sabine, LA	2.7 Bcfd	Cheniere LNG
Humboldt Bay, CA	0.5 Bcfd	Calpine
Mobile Bay, AL	1.0 Bcfd	ExxonMobil
Somerset, MA	0.65 Bcfd	Somerset LNG
Louisiana Offshore	1.0 Bcfd	McMoRan Exp.
Belmar, NJ Offshore	N/A	El Paso Global
So. California Offshore	0.5 Bcfd	Crystal Energy
Bahamas	0.5 Bcfd	El Paso Sea Fare
Altamire, Tamaulipas	1.12 Bcfd	Shell
Baja California, MX	1.3 Bcfd	Sempra
Baja California	0.6 Bcfd	Conoco-Phillips
Baja California - Offshore	1.4 Bcfd	Chevron Texaco
Baja California	0.85 Bcfd	Marathon
Baja California	1.3 Bcfd	Shell
St. John, NB	0.75 Bcfd	Irving Oil & Chevron Canada
Point Tupper, NS	0.75 Bcf/d	Access Northeast Energy
Harpswell, ME	0.5 Bcf/d	Fairwinds LNG - CP & TCPL
St. Lawrence, QC	N/A	TCPL and/or Gaz Met
Location	Capacity	Developer
Lázaro Cárdenas, MX	0.5 Bcfd	Tractebel
Corpus Christi, TX	1.0 Bcfd	ExxonMobil
Gulf of Mexico	1.0 Bcfd	ExxonMobil
Sabine, LA	1.0 Bcfd	ExxonMobil
Providence, RI	0.5 Bcfd	Keyspan & BG LNG

Endesa will invest •3.7 billion ($4.55 billion) to boost its installed generating capacity in Spain by 25 percent between 2004 and 2008. This will result in 5,847 MW of new capacity over the four-year period. Spain's demand for electricity is expected to increase 30 percent by 2010. Most of the new capacity will be fueled by natural gas.

Washington Group currently is working on eight task orders awarded by the U.S. Army Corps of Engineers. The tasks in Iraq include: refurbishing, converting, or installing 13 electrical generators at power plant complexes in northern Iraq.

GE has received a $78 million contract to provide four 250 MW pump/turbine and motor/generator sets, auxiliary equipment and services for a new, 1,000 MW pumped-storage hydropower station. The Jiangsu Pumped Storage Power Co. Ltd. awarded the contract for the equipment to GE as the prime contractor for the project. ABB is a subcontractor on the project, providing a CSCS (computer supervisory control system) and auxiliary electrical systems.

The pump turbines are vertical shaft, single-stage, reversible Francis machines. Rated output in turbine mode will not be less than 255 MW, while the maximum pump input power in pump mode will not exceed 275 MW. The GE equipment will be built in Norway, Finland and Canada. The site installation will begin in the second half of 2005 with the first unit scheduled to enter commercial operation on August 31, 2007. The other units are set to begin operation in subsequent intervals of five, four and three months, respectively.

A 25 percent boost in installed capacity last year brought the total up to 40,000 MW. Europe added more than 5,000 MW while the U.S. added under 2,000 last year.

Aquila has entered into an agreement to sell its interests in 12 power plants to Teton Power Funding, LLC, an affiliate of ArcLight Capital Partners, LLC, for $300.9 million. The plants are located in the states of California, Florida, Georgia, Maine, New York and Washington, as well as Jamaica, and represent a net ownership interest of 643 MW.

Sempra Energy will buy American Electric Power Co.'s Coleto Creek Power Station in Texas and nine other Texas power plants for $430 million. Sempra and the private equity fund, Carlyle/Riverstone, will be joint owners of the 10 plants with combined generating capacity of 3,813 MW. The transaction includes six active power plants capable of generating 1,950 MW and four inactive power plants with capacity of 1,863 MW. Included in the acquisition are

German electricity companies expect to build 45 new power plants with a combined capacity of 24,000 MW by 2020. The new plants would partly replace the current base of 119,000 MW total capacity. The growth is based on a rise in power prices to support new construction and stability in gas prices. The company took the view that existing nuclear plants would be able to run their natural lifespan rather than be closed prematurely as required under current legislation. If there is no backtracking on nuclear phase out, a much larger construction program would be needed.

The study predicted 15 new hard coal plants, four brown coal facilities and 26 gas-fired plants coming on stream. Power demand over the period 2003-2020 would need to grow an overall eight percent to justify the forecast.

The Fan Group (Flakt Woods) Ceases Manufacturing in Former Garden City Facility

The Fan Group Inc., formerly Garden City Fan, is ending its manufacturing operation in Niles, Michigan. Engineering, sales, project management, purchasing, administration, service and installation functions, which employ about 50 people, will remain. The Fan Group Inc. makes large fans used in such applications as metals and cement manufacturing, the petrochemicals industry, ventilation for highway and subway tunnels, power generation, air pollution control, and wind tunnels used in designing automobiles and aircraft. Fan Group Inc. is a subsidiary of Flakt Woods Group, which is based in Switzerland. It has had numerous owners since the 1970s. Wheelabrator-Frye Inc. bought it in 1972. Signal Companies Inc. bought Wheelabrator in early 1983. Later that year Signal sold the company to George Bauer, who previously was majority owner and president. In 1988 he sold it to Flakt, Inc.

In 2002 Global Air Movement bought the Flakt air-handling business from ABB, a Swiss company, and merged it with a British company it owned, Woods Air Movement Ltd., to form Flakt Woods Group. That company provides ventilation products and services to industries and buildings worldwide.

State	Project	Size (MW)	Fuel
AZ	Welton-Mohawk II	260	Gas
AZ	Gila Bend	845	Gas
AZ	Vail (Rita Ranch)	150	Gas
AZ	Ambos Nogales	500	Gas
AZ	Winchester	750	Gas
CA	Inland Empire	670	Gas