American Electric Power’s (AEP’s) Ohio unit has asked the state’s Public Utilities Commission for permission to essentially charge customers for costs to operate nine unregulated coal-fired units, a move the company says will address market volatility and ensure the economic viability of Ohio’s generation.
AEP Ohio on Oct. 3 proposed an “expanded” power purchase agreement (PPA) that will entitle the company to the capacity, energy, and ancillary service output of AEP’s share of the units at four coal plants totaling about 2.7 GW: Cardinal Unit 1; Conesville Units 4, 5, and 6; Stuart Units 1, 2, 3, and 4; and Zimmer Unit 1.
Under the agreement, AEP Ohio would then bid energy, capacity, and ancillary services associated with those units into the PJM market for their remaining life and pass along the resulting cost (or net benefits) to customers through a previously proposed nonbypassable PPA surcharge.
“The PPA proposal allows customers to take advantage of market opportunities while providing added price stability,” said Pablo Vegas, AEP Ohio’s president and chief operating officer in a statement. “This rate structure will act as a hedge to partially shield customers from the impacts of market volatility.
“If market prices remain low, the rider would be a minimal net charge to customers while the customers also benefit from the low market prices. If market prices increase, the PPA rider would be a net credit to customers. Although they also will be paying higher market prices, those prices will be offset by the credit achieved through the PPA. Based on a 10-year projection, this PPA will provide an incremental customer benefit of $224 million,” he said.
Vegas said the measure is necessary because current market conditions in Ohio “are such that even viable plants that are environmentally compliant may be forced to shutter for economic reasons causing our reliance for power from others to grow.”
Since 2008, Ohio has been transitioning from the traditional regulated model of vertically integrated utilities to a more market-based approach. Last year, Dayton Power and Light became the fourth and final Ohio utility to move to a competitive model where its generation assets are spun off from the utility and electricity is sourced from a series of competitive auctions. The company joined FirstEnergy, Duke Energy, and AEP.
The Public Utilities Commission of Ohio (PUCO) has hailed the “competitive market” model as a driver for low and stable power prices as well as innovation. “When generation assets are no longer vertically integrated, utilities can no longer favor their own generation, allowing for competitive suppliers to enter the marketplace,” as former PUCO Chair Todd Snitchler told a state legislative oversight committee last year.
Snitchler noted that incentivizing new generation is necessary because utilities in the coal-heavy state had decided, in order to comply with federal environmental rules, to retire more than 6.5 GW of coal generation through 2015—closures that could result in an almost 20% reduction in installed capacity in Ohio.
But most of Ohio’s utilities are flailing. Like AEP, FirstEnergy and Duke Energy have sought price guarantees for unregulated plants. FirstEnergy on Aug. 4 asked PUCO to approve a proposed electric security plan that essentially calls for a PPA between its regulated Ohio distribution utilities and FirstEnergy Solutions, an unregulated generation affiliate.
This February, meanwhile, Duke Energy announced it would sell interests in 13 power plants in the Midwest after Ohio regulators rejected the company’s request to bill customers in the state an additional $729 million to help cover the gap between power plant costs and wholesale power prices.
Similar utility troubles aren’t just facing Ohio companies. On Sept. 29, Exelon’s senior vice president of federal regulatory affairs and wholesale market policy, Kathleen Barron, told the Illinois Commerce Commission that rate hikes will be necessary to keep that state’s nuclear plants operational to help Illinois meet carbon goals outlined in the proposed federal rule for existing power plants.
Barron reportedly told commissioners that an increase of about $6/MWh would improve Exelon’s nuclear revenue concerns in Illinois.
According to an analysis released by the Nuclear Energy Institute on Sept. 30, if Exelon’s Byron, Clinton, and Quad Cities nuclear power plants shut down prematurely due to “a combination of economic and policy factors,” output losses to Illinois could range from $3.6 billion to $4.8 billion.
—Sonal Patel, associate editor (@POWERmagazine, @sonalcpatel)