The Florida Siting Board in mid-August approved a site certification application by Progress Energy to build a two-unit nuclear power plant in Levy County.
Progress Energy plans to build two Westinghouse AP1000 1,100 MW nuclear reactors at the site. Florida’s governor and Cabinet, serving as the Siting Board, unanimously approved the company’s application.
The vote is the second of three major approvals needed before the company can begin building the nuclear plant. In July 2008, the Florida Public Service Commission approved the plant’s “needs case.” The last remaining major decision is expected from the Nuclear Regulatory Commission in early 2012.
Progress Energy filed its site application with the Florida Department of Environmental Protection in June 2008. After review and public hearings, an administrative law judge last spring supported approval.
Earlier this year, the company said it would delay the project construction timetable, which pushed back the original in-service date of 2016 by a minimum of 20 months. The company said a new project timeline depends on negotiations currently underway with its engineering, procurement and construction vendors.—David Wagman
BPA Rules Address ‘Explosive’ Wind Power Growth
The Bonneville Power Administration in the Pacific Northwest has run smack into an issue that may well be repeated elsewhere as wind power gains a larger share of the electric power generation mix.
The issue is wind integration and, more to the point, how to manage operational and cost allocation issues that arise as wind power projects come into service. It also touches on public perceptions about wind and what role it can and can’t play in meeting electricity demand.
BPA Administrator Steve Wright wrote in a July 21, 2009 decision that while the “explosion of wind power on the BPA system” since 2005 should be cheered and further encouraged, his agency “cannot responsibly ignore the fact that the large amount of wind on our system has also led to operational challenges.” Challenges include risks to reliability, substantial costs and the need to appropriately allocate them.
On August 6, BPA carried a record 2,000 MW of wind-generated electricity. It crossed the 1,000 MW threshold in January 2008.
BPA’s tariff decision adopted a rate of $5.70/MWh for wind integration or wind balancing services. The charge is less than half the $12/MWh BPA initially proposed. The decision and tariff could, according to law firm Stoel Rives, signal the broader wind industry that transmission providers may “change course as they react to increasing amounts of wind being integrated into the grid.” Stoel Rives represented a group of renewable energy companies during the proceedings.
Whether or not the BPA’s tariff approach wins any followers elsewhere remains to be seen. “Gosh, I hope not,” said Brandon Kirby, a consultant who co-authored a report last year for the American Wind Energy Association and the National Renewable Energy Laboratory. In it, Kirby and co-author Michael Milligan wrote that when wind power plants serve load within a host balancing area, no additional capacity is required to integrate wind power into the system. That’s because the wind energy displaces conventional generators’ energy.
“When wind serves load outside the host balancing area, there can be additional capacity requirements,” the report said. How much depends in part on the length of the market period: faster markets are better able to mitigate this requirement and slower markets will exacerbate the capacity requirement.
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For example, in developing its regional power plan, the Northwest Power and Conservation Council applies a discount to wind when it figures in system capacity, said Tom Karier, Washington member of the Council. That means planners count on 5 percent of a wind farm’s nameplate capacity to be generating at times of peak load. For energy planning purposes, the Council considers 30 to 35 percent of nameplate capacity. And, using smart grid resources, operational tools and reserve generation, wind power can become even more useful and predictable as a substitute for baseload capacity. “Wind without backup is an intermittent resource,” Karier said.
In an interview, Kirby said he was disappointed BPA chose to impose a wind integration tariff. He said the issue might have been resolved by adopting “fast-market” sub-hourly scheduling, similar to what is used in the MISO (Midwest) and ERCOT (Texas) regions. Sub-hourly scheduling opens access to more “maneuverable capacity” within a control area and makes accommodating wind much cheaper, he said.
A large part of integrating wind into a system is managing uncertainty that exists around forecasts, said John Dumas, manager of operations planning for ERCOT. Any resource forecast will contain a degree of uncertainty. Planners quantify the uncertainty and then make certain they have enough reserve capacity to cover it. ERCOT’s approach is to buy enough reserve capacity to cover 95 percent of the forecast errors seen over the previous 90 days. Dumas said ERCOT takes a conservative approach to forecasting wind using an “80 percent of exceedance” forecast. That essentially means that 80 percent of the time the wind resource will exceed the forecasted number.
Wright, in a preface to the 541-page BPA decision, said the power authority’s challenges with wind integration have been exacerbated because “nearly 80 percent of the wind on the BPA system is exported to other balancing authority areas.” Failing to solve the problem threatens to limit the amount of wind power than can be interconnected with the BPA transmission system. BPA expects to move from a system that has 20 percent peak wind-to-peak load today to nearly 40 percent peak wind-to-peak load over the next two years.
A decade ago, wind capacity on BPA’s system was 25 MW. Today, more than 2,000 MW of wind is interconnected to its 10,500 MW peak load balancing area. That capacity could grow to 6,000 MW by 2013, placing BPA among the utilities with the highest concentration of wind energy in the United States.
As part of its larger 2010 wholesale power and transmission rate adjustment proceeding, BPA took up the issue of wind integration. It said wind resources are producing large ramp events over short periods of time. In general, these output changes had not been predicted in hourly schedules submitted by wind operators, even when the ramp occurred over the course of several hours.
As a result, BPA said it needs to reserve parts of its hydroelectric system to back up wind in case unscheduled wind ramps occur unexpectedly.
“Historically BPA has used the Federal hydrosystem to provide reserves for all variability that occurs within its transmission network, but wind has presented unprecedented variability.”
BPA said the scheduling inaccuracy problem has been aggravated by its own policy. Starting in 2002 BPA exempted wind operators from penalties targeted at scheduling inaccuracies. It created the exemption recognizing that wind is a variable resource not under the operator’s control and that the penalties were aimed at discouraging generation operators from trying to take advantage of market prices by knowingly providing inaccurate schedules.
BPA said that as wind has grown on its system, its “lenient policy” has led to “rather indiscriminate use of balancing services even when within the control of wind operators.”
It said its new policies have begun to alter this unwanted behavior.
For example, prior to its actions to investigate the issue, BPA said the wind fleet was operating at roughly two-hour “persistence scheduling accuracy.” In recent months this has improved to a “one-hour persistence overall” with some operators approaching 30-minute persistence.
Persistence scheduling accuracy is a measure of how accurate the power generation schedules are that are submitted by wind energy producers. The accuracy indicator measures the difference between wind energy that is actually generated and when the schedule said that amount of energy was to have been generated.
For example, if a wind project generates 100 MW at 1 p.m., but the schedule says it will not generate 100 MW until 3 p.m., that is a two-hour persistence scheduling accuracy said Michael Milstein of the BPA’s Public Affairs Office. If the scheduling forecast was 30 minutes off, that would represent a 30-minute persistence scheduling accuracy.
“Wind operators are investing in meteorologists and 24-7 scheduling operations in order to better their scheduling accuracy,” BPA said in its July 21 decision. What’s more, moving away from two-hour persistence allows BPA to carry fewer reserves and delay adding new balancing reserve sources.
In arguing that its proposed charge penalizes wind generators for wind’s natural variability, BPA said “wind generators themselves recognize that wind generation is much more variable than other generation.” It said wind generation puts stresses on the transmission system that thermal generation and load do not. BPA said historical data showed it has experienced persistent and large deviations. The larger the deviation the more balancing reserves BPA must deploy and the larger the impact to the system’s hydro operations.
“Penalties for persistent and large deviations are necessary because such deviations may reduce BPA’s ability to provide balancing reserves to maintain load and resource balance.”—David Wagman
Dynegy Sells 9 Generating Assets
Dynegy Inc. agreed to sell nine power generating assets to LS Power for $1.025 billion. The plants are in Kentucky, Illinois, Michigan, Connecticut, Arizona and Texas.
Dynegy also said it planned to cut capital expenditures, with a targeted range of $25 million to $30 million in savings a year; reduce operational expenditures, with a targeted range of $30 million to $40 million in savings a year; and reduce general and administrative expenditures, with a targeted range of $40 million to $45 million in savings a year.
Under terms of the agreement with LS Power, Dynegy will receive $1.025 billion in cash and 245 million of its Class B shares. In exchange, Dynegy will sell five peaking and three combined-cycle generation assets, as well as Dynegy’s remaining interest in a project under construction in Texas. LS Power will also receive $235 million principal amount of 7.5 percent senior unsecured notes due 2015. The transaction is expected to close later this year.
The generation assets include five peaking facilities (Riverside and Bluegrass in Kentucky, Rocky Road and Tilton in Illinois and Renaissance in Michigan) as well as three combined-cycle facilities (Arlington Valley and Griffith in Arizona and Bridgeport in Connecticut). –Sharryn Harvey
Siemens Receives Flex-Plant 30 Order
Siemens Energy has been awarded a contract from Northern California Power Agency to supply a $140 million, 280 MW, natural gas-fired combined cycle power plant. The order is the first in the U.S. for Siemens’ Flex-Plant 30 technology. The plant will be in Lodi, Calif. and is designed to deliver 200 MW of power to the grid within 30 minutes.
The SCC6-5000F single-shaft Flex-Plant 30 is designed for intermediate to continuous duty and is capable of daily cycling at efficiencies of over 57 percent. The power plant will serve the energy needs of 14 different project participants.—Sharryn Harvey
TVA Reconsiders Bellefonte Nuclear Site
The Tennessee Valley Authority said it is again reconsidering what to do with its Bellefonte site in Alabama.
TVA had considered either completing units 1 and 2, constructing two new units or building four units. It is now preparing a supplemental environmental impact statement with three alternatives: completing and operating either unit 1 or 2, building a new Westinghouse AP1000 nuclear unit or not operating a nuclear unit at the site at all.
The SEIS will also evaluate the impact of upgrading several existing 161kV and 500 kV transmission lines and switchyards needed for single-unit operation. TVA expects to finalize the SEIS in 2010.
The Bellefonte plant originally planned to house two reactors. Construction permits for units 1 and 2, which are 1,200 MW pressurized water reactors, were issued in 1974. TVA halted construction in 1988 after power demand decreased, leaving Unit 1 88 percent finished and Unit 2 58 percent done. TVA cancelled both units in 2005 to look into other uses for the site. In August 2008 TVA requested reinstatement of the units’ construction permits.—Sharryn Harvey
TVA submitted a COL application to the U.S. Nuclear Regulatory Commission in October 2007 for the siting of two AP1000 reactors, which would be named units 3 and 4. The NRC is still considering the COL application for the units.—Sharryn Harvey
DOE Funds Research Centers
The U.S. Department of Energy is funding $377 million for 46 new Energy Frontier Research Centers located at universities, national laboratories, non-profits and private firms nationwide.
The centers will initially get $2 to $5 million a year for five years to advance projects in renewables, electricity storage and transmission, coal, nuclear and carbon capture and storage. Of the $377 million, $277 million of it comes from the Recovery Act. The remaining will come from the DOE’s fiscal year 2009 budget.—Sharryn Harvey
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