Posted on March 9, 2018 by Eugene Trisko
In the last decade, every aspect of the electric utility business has changed except one. We’ve experienced a revolution in how and where electricity is generated, consumed, and distributed. What hasn’t kept up are the rules governing the market. They haven’t adapted to changing technologies, fuels or consumer demands, and they are leading us toward a future electric supply mix dominated in many markets by intermittent renewable generation backed up by natural gas power plants.
Hundreds of coal-fueled generating plants have closed over the past several years due to lower natural gas prices and the costs of compliance with EPA’s 2012 mercury regulations. Some nuclear units in competitive power markets also have shut down prematurely, and many more are at risk because they cannot recover their costs under current electricity market rules. Illinois, New York, and Pennsylvania have each turned to legislative and regulatory remedies to shore up the economic viability of their nuclear plants.
To help ensure fuel diversity and resilience of the electric power grid, the U.S. Department of Energy transmitted a proposed rule to the Federal Energy Regulatory Commission in September 2017 to provide full cost recovery for coal and nuclear units operating in competitive power markets. FERC issued the DOE proposed rule in a Notice of Proposed Rulemaking (NOPR) on October 10, 2017 (82 Fed. Reg. 46940). energy.gov/sites/prod/files/2017/09/f37/Notice%20of%20Proposed%20Rulemaking%20.pdf
The basic premise of FERC’s Grid Resiliency Pricing Rule was that baseload coal and nuclear units provide unique benefits to the electric grid due to the security of their “on the ground” fuel supplies and their inherent stability and reliability. Most natural gas generation relies on “just in time” gas deliveries through pipelines, and much of the gas supply is subject to interruptible contracts. Intermittent renewable sources such as wind and solar do not provide the same grid stability as 24/7 baseload power units.
FERC’s proposal sought to correct a deficiency in the way that power producers are compensated. Current market rules shortchange baseload generators and overpay variable and marginal producers that piggyback on the reliability, voltage smoothing and other services provided by baseload coal and nuclear plants. Ensuring fuel diversity in the power generation fleet is an effective way to minimize risks to the electric grid posed by extreme weather events, fuel supply interruptions, terrorist acts, and other unplanned disruptions.
The NOPR generated a firestorm of opposition in comments filed by state regulators, utilities, regional power grid operators, natural gas and renewable energy interests, and environmental advocates. Numerous comments argued that existing market structures were adequate to prevent threats to electric reliability, and that the rule was not based on substantial evidence. Several former FERC chairmen spoke publicly in opposition to the rule for its “interference” with market mechanisms.
Faced with this opposition, a prominent FERC member floated a proposed “interim rule” allowing regional grid operators to provide rate adjustments sufficient to avoid the retirements of additional baseload power units while FERC initiated a longer-term study of grid resilience and electric market design. But with two new members being added to the Commission in late 2017 following Senate confirmation – including a new Chairman – the interim rule failed to gain traction.
On January 18, FERC rejected the DOE rule in an order calling for the creation of a new docket (No. AD18-7-000) “to holistically examine the resilience of the bulk power system.” The new docket will assemble data and analyses by regional grid operators and others “to provide information as to whether FERC and the markets need to take additional action on resilience of the bulk power system.” Meanwhile, grid operators such as PJM are considering their own pricing reform measures.
As the NOPR debate was unfolding, the eastern electric grid was challenged by the “Bomb Cyclone” that sent temperatures plunging across the eastern seaboard. New England power generators ran low on natural gas supplies and had to switch to highly-emitting oil generators, nearly exhausting their available “on the ground” oil supplies. Both natural gas and coal units in the Midwest and Mid-Atlantic regions experienced some power interruptions, with gas units experiencing a larger degree of unavailability. With the support of the remaining coal and nuclear baseload fleets, the East Coast and Midwest avoided catastrophic service interruptions.
The question left unanswered by the Bomb Cyclone was how a future eastern grid with much higher dependence on gas and renewable generation, and lower availability of coal and nuclear baseload generation, would perform under similar or more severe conditions. In late February, DOE announced that it will develop a quantitative model for assessing long-term reliability risks based on regional changes in generation portfolios. The DOE modeling effort should provide key inputs to FERC’s examination of reliability issues. In its order rejecting the NOPR, FERC “recognize(d) that it must remain vigilant with respect to resilience challenges, because affordable and reliable electricity is vital to the country’s economic and national security.” https://www.ferc.gov/CalendarFiles/20180108161614-RM18-1-000.pdf
A long-term reliability study will shed needed light on the multiple risks to electric reliability associated with the loss of coal and nuclear baseload generating plants. Once baseload power resources are shut down, they cannot be reactivated. Turbines warp under their own weight. Recent FERC projections show the loss of an additional 26,000 Megawatts of coal and nuclear baseload capacity by 2020 (FERC Infrastructure Update, Nov. 2017). https://www.ferc.gov/legal/staff-reports/2017/nov-energy-infrastructure.pdf
FERC’s “holistic” assessment of the long-term risks confronted by our rapidly changing power generation industry cannot be completed soon enough. While the Commission’s study process has avoided any hard decisions on reforming market pricing rules for the time being, the ongoing trend of baseload capacity retirements is likely to continue for the indefinite future.
The writer is an adviser to labor unions concerned about electric reliability and fuel diversity issues.