Virginia Electric and Power d/b/a Dominion North Carolina Power on Aug. 5 applied to the North Carolina Utilities Commission to adjust the fuel component of its electric rates to become effective Jan. 1, 2017, and remain in effect for the calendar year 2017.
DNCP serves approximately 120,000 customers in North Carolina, with a service territory of about 2,600 square miles in northeastern North Carolina, including Roanoke Rapids, Ahoskie, Williamston, Elizabeth City, and the Outer Banks. Dominion North Carolina Power’s test period for this proceeding is the 12-month period ending June 30, 2016. The utility is a subsidiary of Dominion Resources (NYSE: D).
Bruce E. Petrie, Manager of Generation System Planning for Virginia Electric and Power, testified that during the test period, the company’s coal units generated 23,160 GWh of energy. Mt. Storm Units 1-3 in West Virginia performed at equivalent availability (EA) factors of 88.8%, 87.3% and 63.4%, respectively. Chesterfield Units 5-6 in Virginia had EA factors of 77.2% and 81.4%, respectively. Virginia City Hybrid Energy Center (VCHEC) had an EA of 73.5% during the test period.
The aggregate capacity factor was 91.8% for the company’s nuclear units for the test period. The company’s nuclear fleet capacity factor was higher than the industry five-year historical average for comparable units. The North American Electric Reliability Corp. (NERC) 2009-2013 five-year industry average net capacity factor for Pressurized Water Reactors is 87.8% for 800-999 MW units. The net capacity factors during the historic test period for the company’s nuclear units ranged from 83.8% for Surry Unit 2 to 102.2% for North Anna Unit 1.
During the test period, nuclear generation supplied 33%; coal-fired generation supplied 28.3%; combined cycle and combustion turbine generation supplied 28.1%; and power transactions (net) supplied 7%. These four energy sources accounted for 96.5% of the total energy supply. Natural gas-steam, oil, biomass, and hydro generation provided the remaining 3 .5% (net) of the energy supplied.
The company experienced an over-recovery of fuel expenses during the test year. This fuel over-recovery was primarily driven by mild weather, lower commodity prices, and the addition of new and efficient natural gas generation. In addition, the company optimized its diverse fleet of generating assets to reduce system fuel expense.
The addition of the 1,358-MW Brunswick County natural gas-fired combined cycle station in April 2016 will provide a benefit to the system fuel expense with a full year of operation, said Petrie. For this case, the system fuel expense was adjusted to reflect the expected fuel benefits related to the Brunswick County station. The system fuel savings, calculated using the PROMOD production cost model, are forecasted to be approximately $48.5 million in 2017.
There will be changes to the non-utility generator (NUG) contracts as well, with two NUG contracts scheduled to expire during 2017. The 605-MW contract with Doswell will end in May 2017, and the 116 MW and 85 MW contracts with the Spruance facility will end in July 2017. The company also expects additional growth in solar energy purchases.
Ronnie T. Campbell, the Supervisor of Accounting for Dominion Generation, which includes responsibility for Virginia Electric and Power, said the NUG contract with Edgecombe Genco LLC expired Oct. 14, 2015. For dispatchable NUGs that do not provide actual fuel costs, the company continues to include 85% of the reasonable and prudent energy costs in the EMF calculation (Doswell Complex and Hopewell Cogeneration). The contract with Hopewell Cogeneration expired July 31, 2015.
Various fuels selling for low prices due to over-supply
Gregory A. Workman, the Director-Fuels, said about fuel markets in general: “Across the world, commodity markets continue to remain oversupplied and prices have overall remained depressed, with a slight rebonnd in the spring of 2016. Domestic natural gas production remains near a record high, primarily as a result of dramatic increases in production from the Marcellus and Utica shale regions. Natural gas inventories ended the traditional withdrawal season in 2016 at near record levels. As a result, from July 2015 through the first half of 2016, Henry Hub natural gas cash prices have remained below $3.00/MMBtu.
“The oversupply of competitively priced natural gas continues to impact coal markets, providing an economic incentive for utilities to switch fuels from coal to natural gas for power generation. This has resulted in lower demand for coal, higher than average coal inventories, and ultimately lower coal prices. A depressed export market for both thermal and metallurgical coal has further increased coal supplies available for use in power generation. The Central Appalachian (CAPP) coal price has traded at levels last seen in 2007. As market conditions have deteriorated, the number of bankruptcies among coal suppliers has increased. As a matter of practice, the Company routinely monitors the financial health of its suppliers and their ability to fulfill the Company’s contracts on behalf of customers and continues to do so in the context of current coal market instabilities.
“Increased production of domestic shale oil, as well as OPEC’s recent decision not to reduce production, has led to a worldwide oversupply of oil and petrolemn products. As a result, West Texas Intermediate crude prices have dropped below $50/bbl. The significant decline in No. 2 and No. 6 fuel oil prices is the direct result of falling crude oil prices in global markets.”
NUG deals to expire this year are with coal, gas plants
Dominion did not offer details on the NUG contracts in the Aug. 5 fuel cost application. But in an integrated resource plan filed April 29 at the Virginia State Corporation Commission and the North Carolina Utilities Commission, the utility outlined these NUG contracts, with plant locations, fuels, MW ratings and contract end dates:
- Spruance Genco, Facility 1 (Richmond 1), Richmond, Va., Baseload, Coal, 115.5 MW (summer), contract start 8/1/1992, contract expiration 7/31/2017;
- Spruance Genco, Facility 2 (Richmond 2) Richmond, Va., Baseload, Coal, 85 MW summer, contract start 8/1/1992, contract expiration 7/31/2017;
- Doswell Complex, Ashland, Va, Intermediate, Natural Gas, 605 MW summer, contract start 5/16/1992, contract expiration 5/5/2017;
- Roanoke Valley II, Weldon, N.C., Baseload, Coal, 44 MW summer, contract start 6/1/1995, contract expiration 3/31/2019;
- Roanoke Valley Project, Weldon, N.C., Baseload, Coal, 165 MW summer, contract start 5/29/1994, contract expiration 3/31/2019; and
- SEI Birchwood, King George, Va., Baseload, Coal, 217.8 MW summer, contract start 11/15/1996, contract expiration 11/14/2021.
The IRP says the utility may or may not re-up with any of these power suppliers when the contracts expire. It said: “At the expiration of these NUG contracts, these units will no longer be modeled as a firm generating capacity resource. The Company assumed that NUGs or any other non-Company owned resource without a contract with the Company are available to the Company at market prices; therefore, the Company’s optimization model may select these resources in lieu of other Company-owned/sponsored supplyor demand-side resources should the market economics dictate. Although this is a reasonable planning assumption, parties may elect to enter into future bilateral contracts on mutually agreeable terms. For potential bilateral contracts not known at this time, the market price is the best proxy to use for planning purposes.”