The Virginia State Corporation Commission’s recent approval of a Dominion Virginia Power (DVP) plan to convert three small coal plants to firing biomass should be a major step in the utility achieving renewable energy standards in both Virginia and North Carolina.
David Eichenlaub, Assistant Director in the Commission’s Division of Energy Regulation, said in March 30 testimony that DVP is participating in Virginia’s Voluntary Renewable Energy Portfolio Standards (RPS) goals and is required to comply with North Carolina’s Renewable Energy and Energy Efficiency Portfolio Standard Plan (REPS). Both the Virginia and North Carolina standards permit the company to satisfy renewable power objectives through the generation of renewable energy, the purchase of renewable energy credits (RECs), or a combination of these options.
Several staff officials were included in March 30 testimony filed at the commission within an ongoing case covering DVP’s latest integrated resource plan (IRP), which was initially filed with the commission last September. DVP, also known as Virginia Electric and Power, is a unit of Dominion Resources (NYSE:D).
DVP filed for and on March 16 received approval to convert three coal-fired facilities to biomass for a total of 153 MW. The Virginia City Hybrid Energy Center is expected to begin commercial operation this summer and to contribute 59 MW of renewable capacity as it co-fires coal with biomass. The 2011 IRP includes development of a 4 MW solar facility and relies on renewable energy from existing generating units, including non-utility generators (NUGs). The utility’s IRP also assumes the purchase of RECs.
The company’s preferred resource plan does not include the construction of additional renewable resources. The Alternative Renewable Plan, which specified the construction of renewable generation within the company’s service territory, chose additional renewable facilities such as wind and solar. DVP found that plan to be 17.68% more expensive than the Preferred Plan, Eichenlaub noted. The Preferred Plan includes the purchase of RECs as the most economic means of meeting renewable objectives.
Dominion plans three Rs; retire, retrofit and repower
John Stevens, Principal Utilities Engineer with the commission’s Division of Energy Regulation, pointed out that DVP’s existing generation fleet consists of 100 generation units, which includes four nuclear, 22 coal, one biomass, two natural gas, two heavy oil, eight combined cycle (CC), 41 combustion turbines (CT), six pumped storage and 14 hydro units with a summer capacity of about 16,987 MW.
In May 2011, the Bear Garden CC plant, located in Buckingham County, Va., came into service. The company currently owns and operates several renewable resources including its wood-burning Pittsylvania plant (83 MW) and four hydro facilities; Gaston (220 MW), Roanoke Rapids (95 MW), Cushaw (2 MW), and North Anna (1 MW).
The company continues to evaluate options for existing unit uprates as a cost-effective means of increasing generating capacity and improving system reliability. Between 2009 and 2011 the company’s investment in its existing generation fleet yielded net capacity additions of 172 MW.
Additionally, DVP states that the U.S. Environmental Protection Agency has proposed new regulations that are expected to affect certain units in its current fleet of generation resources. These regulations are designed to regulate air, water and solid waste. DVP also notes that, in compliance with existing environmental regulations, it connected Chesterfield Units 3, 4 and 5 to a new pollution control system in 2011, which included an SO2 scrubber.
The 2011 IRP includes the following impacts to existing generating resources in terms of retrofitting and repowering, which may be revised when certain EPA regulations are finalized:
- Retrofit – Possum Point Unit 5 (779 MW) and Yorktown Unit 3 (804 MW) are in the IRP to be retrofitted with selective non-catalytic reduction (SNCR) for NOx control by 2015.
- Repower – On March 16, the commission approved conversion of the Altavista, Hopewell and Southampton County coal plants to biomass.
- Repower – The coal-fired Bremo plant is in the IRP to be repowered by natural gas subject to regulatory approval by 2014. The two coal units currently in use at the station were put into service in 1950 and 1958.
- Repower – The coal-fired Yorktown Unit 2 (156 MW) is in the IRP to be repowered by natural gas and oil by 2015.
As part of the 2011 IRP process, the utility analyzed a number of options for several of the older coal- and oil-fired units that may not be compliant with impending environmental rules that begin to take effect in 2015. Based on this analysis, the 2011 IRP includes the following potential retirement options for existing generating resources:
- Chesapeake Units 1 (111 MW) and 2 (111 MW) and Yorktown Unit 1 (159 MW) are in the IRP to be retired by 2015;
- Chesapeake Units 3 (156 MW) and 4 (217 MW) are in the IRP to be retired by 2016;
- Yorktown Units 2 (156 MW) and 3 (804 MW) are to be retired by 2022; and
- the coal unit at the North Branch plant, located in Bayard, W.Va., is currently in cold reserve status and will be retired from service once the gas-fired Warren County plant begins commercial operation.
The company is also evaluating future blackstart resources based on the future generation retirements. Potential retirements include some generation facilities that are currently designated as blackstart units. Blackstart units are capable of starting without an outside electrical supply or are able to remain operating at reduced levels when automatically disconnected from the grid. The North American Electric Reliability Corp.’s Reliability Standard EOP-005 requires the Transmission Operator to have a plan to restore its system following a complete shutdown (i.e., blackout).
Currently, DVP’s tentative plan is to request about 250 MW of additional blackstart generation in increments of 50 MW per year for five years between 2013 and the end of 2018. The company will employ PJM Interconnection‘s Black Start Replacement Process to solicit additional blackstart generation.
New coal plant helps fill near-term needs
DVP’s Virginia City Hybrid Energy Center (VCHEC), a 585-MW coal and biomass facility, is located in Wise County, Va. The station’s targeted commercial operation date is summer 2012. The plant will use circulating fluidized bed (CFB) technology to burn a wide range of coals and waste coal from abandoned mines in the area. Additionally, the station will be capable of burning up to 20% biomass such as wood waste and wood byproducts.
As identified in the IRP, over the next five years (2012-2016), the company plans to add VCHEC and the Warren County plant totaling about 1,920 MW. The company also plans to add the Halifax County Solar facility of 4 MW with battery storage by 2015, and a natural gas CC facility in Brunswick County, with a capacity of about 1,300 MW, by the summer of 2016.
In the long-term (2017-2026), the company plans to add an additional 1,454 MW of baseload capacity and 3,737 MW of intermediate and peaking capacity. Specifically, a third unit at its existing North Anna nuclear plant will primarily meet anticipated baseload growth. Natural gas CC and CT plants will primarily meet anticipated intermediate and peak growth.
On Feb. 2, the commission approved the company’s application for approval to construct and operate the Warren County plant, a 1,337 MW natural gas-fired CC electric generation facility in Warren County, Va. The new generating facility will be a 3×1 CC. Based on the company’s current schedule, this plant will be available to meet 2015 peak capacity and energy demand. According to the utility, this plant is expected to reduce the company’s reliance on market purchases and provide needed infrastructure in Northern Virginia.
The new North Anna Unit 3 would have a summer capacity of 1,454 MW. The utility is expecting the results of the Nuclear Regulatory Commission review of this project by November 2013 and that North Anna Unit 3 would provide needed baseload capacity by 2022.
In addition to the VCHEC, Warren County, Brunswick County and North Anna Unit 3, the company’s IRP also includes plans to construct a mix of potential conventional resources including an additional natural gas CC plant (1,337 MW) and six additional CT plants (400 MW each) totaling about 3,737 MW that will continue to be studied as the resource need is established.