Dominion’s new IRP details coal plant retirements

The outright retirement in 2015 of six coal-fired units at the Yorktown and Chesapeake plants, and the 2014 conversion of the Bremo coal plant to firing natural gas, are major features of an integrated resource plan (IRP) filed Aug. 30 at the Virginia State Corporation Commission (SCC) by Virginia Electric and Power.

Virginia Electric does business in Virginia as Dominion Virginia Power, and does business in North Carolina as Dominion North Carolina Power, where it also filed the new IRP with the North Carolina Utilities Commission. It is a unit of Dominion Resources (NYSE: D).

Dominion plans these changes to existing generation:

  • Bremo Unit 3 conversion from coal to gas, 2014;
  • Bremo Unit 4 conversion from coal to gas, 2014;
  • Possum Point Unit 5 (fired with fuel oil) selective non-catalytic reduction (SNCR) installation, 2018; and
  • Yorktown Unit 3 (fuel oil) SNCR installation, 2018.

The company plans these plant and unit retirements, with summer MW ratings:

  • Chesapeake Unit 1 (coal), 111 MW, 2015;
  • Chesapeake Unit 2 (coal), 111 MW, 2015;
  • Chesapeake Unit 3 (coal), 156 MW, 2015;
  • Chesapeake Unit 4 (coal), 217 MW, 2015;
  • Possum Point CT (fuel oil), 72 MW, 2015;
  • Yorktown Unit 1 (coal), 159 MW, 2015;
  • Yorktown Unit 2 (coal), 164 MW, 2015;
  • Lowmoor CT (fuel oil), 48 MW, 2016;
  • Mt. Storm CT (fuel oil), 11 MW, 2016; and
  • Northern Neck CT (fuel oil), 48 MW, 2017.

Bremo conversion application still pending at the Virginia commission

The company flied for a Certificate of Public Convenience and Necessity (CPCN) with the SCC to repower its coal-fired Bremo station with natural gas in August 2012. Bremo currently has two units, Unit 3 and Unit 4, which have been in service since 1950 and 1958, respectively. Unit 3 has a summer capacity of 71 MW and Unit 4 has a summer capacity of 156 MW. This conversion is expected to reduce the company’s emissions of SO2, NOx, particulate matter, CO2 and mercury.

The company recently completed its Altavista coal-to-biomass conversion and expects to complete major unit modifications to convert the Hopewell and Southampton stations from coal-fired to biomass, with all three converted plants rated at 51 MW each, by the end of 2013.

The majority of the company’s coal generators are equipped with scrubbers and NOx controls. However, the remaining small coal-fired units are without needed emission controls to comply with new and anticipated regulatory requirements. The company’s coal-fired units at the Chesterfield, Mt. Storm, Clover, Mecklenburg and Virginia City Hybrid Energy Center (VCHEC) facilities have flue gas desulfurization to control SO2 emissions. The company’s Chesterfield Units 4-6, Mt. Storm, Clover, Chesapeake Units 3-4, and VCHEC coal-fired units also have selective catalytic reduction (SCR) or SNCR to control NOx.

The company’s 2013 IRP remains largely unchanged compared to its 2012 IRP regarding retrofitting, repowering, and retiring units affected by U.S. Environmental Protection Agency regulations. The expected installations of the SNCR controls on the oil-fired Yorktown 3 and Possum Point 5, which have been delayed, will both be online in 2018.

Two new gas plants in construction

To meet expected load growth, the company filed with the SCC for approval to construct and operate the Warren County Power Station, a 1,337 MW natural gas-powered facility located in Warren County, Va. In February 2012, the SCC granted that approval and the company began construction within days afterward. The station is targeted for commercial operation by 2015.

In November 2012, the company filed an application with the SCC to construct and operate the Brunswick County Power Station, a 1,375 MW natural gas powered facility located in Brunswick County, Va. On Aug. 2, the SCC granted that approval.

There are multiple differences in the 2013 base case forecast used in this plan compared to the base case forecast used in the 2012 plan. The primary changes include lower natural gas and coal prices and updated environmental assumptions reflecting consultant ICF‘s latest views on final and proposed environmental rules.

Over the long-term, the lower price outlook for natural gas is a result of continued increases in production from shale gas development in North America. The outlook for coal prices are lower based on significantly lower Central Appalachian (CAPP) demand than predicted in last year’s forecast due to coal plant retirements and remaining coal plants switching to lower quality, lower cost coals. Those assumed gas and coal prices are redacted from the public version of the IRP.

Third North Anna unit, while not a certainty, undergoes changes

Virginia Electric has included some small wind, solar and biomass projects in this new IRP. The company is also developing a new nuclear unit, North Anna 3, at its existing North Anna station located in Louisa County in central Virginia. The 2013 plan has North Anna 3 achieving commercial operation in October 2024. This is the earliest possible in-service date given permitting and construction lead times. The company emphasized that it has not committed to build North Anna 3 to date but continues to develop the project to assure that this supply-side resource option remains available to customers.

The company has revised its technology selection for North Anna 3 to GEH‘s ESBWR nuclear technology rather than the Mitsubishi Heavy Industries Advanced Pressurized Water Reactor identified in the 2012 plan. This decision was based on a continuation of the competitive procurement process that began in 2009. Since 2009, GEH has continued to refine its design and has made significant progress toward obtaining federal approval. In addition, GEH and its consortium partner Fluor Enterprises provided contract enhancements that are expected to benefit customers and stakeholders over the new unit’s planned 60-year life.

In July 2013, the company submitted a revised application to the U.S. Nuclear Regulatory Commission (NRC) to reflect the change in technology. The company expects to receive the NRC license no earlier than late 2015 and intends to maintain the development option of North Anna 3 for several key reasons. Those reasons include:

  • North Anna 3 will provide much needed baseload capacity to the region in the latter portion of the planning period while enhancing system reliability;
  • nuclear units are near emission-free generation;
  • North Anna 3 will enhance fuel diversity within the company’s generation portfolio, which will in turn, promote fuel price stability for customers; and
  • nuclear power is the lowest cost large-scale dispatchable baseload generating alternative to natural gas.

The need for new nuclear power becomes greater with the future license expirations of the company’s current nuclear facilities. The license expirations of Surry Units 1 (838 MW) and 2 (838 MW) and North Anna Unit 1 (838 MW) occur in 2032, 2033, and 2038, respectively. The license for North Anna Unit 2 (835 MW) will expire in 2040.

One version of the IRP is gas heavy, another version is less so

Besides the Warren and Brunswick County gas projects, the company is also currently in the early stages of development of another natural gas-fueled, combined-cycle (CC) facility. The current forecasted commercial operation date is in 2019. The Base Plan calls for this CC in 2019, then a combustion turbine (CT) addition in 2021, another CT in 2022, another CT in 2023, and then an additional CC in 2027. The alternative Fuel Diversity plan, which relies more on non-greenhouse gas emitting resources, calls for the CC in 2019, a CT in 2022, a CT in 2027 and a CT in 2028. So the diversity plan calls for as much in the way of CT additions as the base plan, but on a delayed schedule, and with no second CC.

Something to be aware of for the coal industry is that Virginia Electric has contracts to take power from several coal-fired independent power plants, with the status of the particular plant becoming a question mark once a contract expires. The coal plants, summer MW ratings and contract expiration time are as follows:

  • Spruance Genco Facility 1 in Virginia, 115.5 MW, expires July 2017;
  • Spruance Genco Facility 2 in Virginia, 85 MW, expires July 2017;
  • Edgecombe Genco (Rocky Mount) in North Carolina, 115.5 MW, expires October 2015;
  • Roanoke Valley II in North Carolina, 44 MW, expires May 2020;
  • Roanoke Valley in North Carolina, 165 MW, expires May 2019; and
  • SEI Birchwood in Virginia, 217.8 MW, expires in November 2021.

There are also a couple of gas-fired IPPs:

  • Doswell Complex in Virginia, 605 MW, contract expires May 2017; and
  • Hopewell Cogen in Virginia, 336.6 MW, expires July 2015.
About Barry Cassell 20414 Articles
Barry Cassell is Chief Analyst for GenerationHub covering coal and emission controls issues, projects and policy. He has covered the coal and power generation industry for more than 24 years, beginning in November 2011 at GenerationHub and prior to that as editor of SNL Energy’s Coal Report. He was formerly with Coal Outlook for 15 years as the publication’s editor and contributing writer, and prior to that he was editor of Coal & Synfuels Technology and associate editor of The Energy Report. He has a bachelor’s degree from Central Michigan University.