Six Glaring Interventions in Competitive Markets — Beyond the Trump Plan

The Trump administration’s attempt to prop up uneconomic “fuel secure” generators in competitive markets is just the latest in a string of recent “extra-market” interventions that experts said imperil independent organized markets for electricity.

In a recent white paper, Raymond Gifford and Matthew Larson, energy partners at Wilkinson Barker Knauer LLP, said the restructured administrative market model (RAMM) has been “trampled by interventions,” both “around market” from the states and in courts, and “in market”—and that the cascade shows “no hint of slowing.”

The RAMM, they note, was intended to yield competitive outcomes. Though the future of the model has been at a tipping point for some time—because “it was never a market in the emergent sense of willing buyers and sellers”— today, it “lays in tatters” as market operators develop solutions to enhance resiliency, reduce carbon emissions, and accommodate state actions.

The paper’s authors warn that “these actions continue to—purposefully or otherwise—ignore the fact hiding in plain sight: the RAMM is flawed and failing, and no model adherent is immune to its symptoms.” At blame are regulatory failures more than market failures, they contend.

Here are six recent developments that illustrate market vulnerabilities.

Exelon’s Unconventional Mystic Reliability-Must-Run (RMR) Contract

According to the authors, no single application could have as much impact on the future of energy markets as the one pending before the Federal Energy Regulatory Commission (FERC) regarding a tariff waiver request by ISO-New England (ISO-NE). Its intention is to keep Exelon’s 2,274-MW Mystic Generating Plant in Boston, Massachusetts, running to address “fuel security risks,” even though Exelon said in March it planned to retire the gas-fired plant when its capacity obligations expire in May 2022 unless it received a two-year RMR contract to recover full cost of service. Exelon later estimated it would need an annual fixed revenue requirement of about $219 million for capacity commitment period 2022/2023 and nearly $187 million for 2023/2024.

On May 28, most stakeholders filing comments with FERC opposed the request. They questioned ISO-NE’s plan to keep open Mystic 8 and 9—two combined cycle gas-fired units with a total winter seasonal capacity of 1,700 MW. The units get fuel from the Everett Marine Terminal, a neighboring liquefied natural gas import hub, rather than relying on pipeline gas.

ISO-NE on May 1 asked FERC to approve waivers by July 2. It said the loss of those units presents “unacceptable fuel security risks,” causing the ISO to deplete 10-minute operating reserves on numerous occasions, which could instigate load shedding during New England winters of 2022–2023 and 2023–2024. Shuttering the units would also mean that the Everett Marine Terminal (known as Distrigas), which Exelon is in the process of acquiring from current owner ENGIE North America, would lose its biggest customer, “substantially diminishing its financial viability” and putting the regional reserve depletion and load shedding at further risk, the ISO argued.

Among commenters were Massachusetts Attorney General Maura Healey, who questioned the legality of using FERC’s waiver process in the “expansive way” ISO-NE proposed, noting that the regional transmission organization was asking to retain power units “not for capacity needs but to ensure ‘fuel security,’ a term that is not defined in the Federal Power Act (FPA), and a concept for which there is no settled or universally accepted definition.”

The Electric Power Supply Association (EPSA), a group that represents companies that mostly bank on wholesale markets for revenues, noted that the request was “premature and over-broad.” EPSA urged FERC to reject it without prejudice. “Additionally, this near-term fix may have the adverse effect of hastily establishing a new reliability criteria to be used to underpin RMR-type arrangements going forward, in the absence of any formal process, stakeholder input or Tariff revision proceeding,” it noted.

The New England Power Generators Association (NEPGA), which filed a complaint against ISO-NE under the Federal Power Act Section 206, suggested that the proposed arrangement could allow Exelon to bid 1,400 MW of Mystic capacity into Forward Capacity Auctions (FCA) 13 and 14 at “zero, potentially displacing as much as 1,285 MW of otherwise economic resources and suppressing capacity prices by as much as $642 million in FCA 13 alone, with the potential for even greater displacement and price suppression in FCA 14.”

For Gifford and Larson, FERC’s decision of ISO-NE’s request “cannot be overstated, and to our mind, it determines the future of the RAMM.”

The Proliferation of Nuclear Zero Emission Credits

For Gifford and Larson, “around market” interventions generally fall into three types: The maintenance fee (or backdoor capacity payment); “the prescriptive replacement capacity approach”; and vertical re-integration, or re-regulation. The backdoor capacity payment approach is especially thriving on the state level.

On May 23, New Jersey’s Gov. Phil Murphy signed a bill that establishes a zero-emissions certificate (ZEC) program that will prop up PSEG’s 2,282-MW Salem and 1,180-MW Hope Creek nuclear plants, which account for 95% of the state’s carbon-free resources. The state joins New York and Illinois, which passed laws subsidizing ailing nuclear facilities in 2016, and Connecticut, whose governor last year signed a controversial bill allowing Dominion’s Millstone plant to participate in its clean energy procurement process. And last week, in a pivotal and underreported move, the U.S. Department of Justice and FERC backed Illinois’ nuclear subsidy program, arguing in an amicus brief that its ZECs—which would provide out-of-market payments for carbon-free nuclear power—does not preempt federal statute.

“If one were to prognosticate which state will be next, the Exelon earnings call is always a good place to start,” the white paper says. In April, it notes, Exelon CEO Chris Crane pointed to Pennsylvania as the next frontier, but Ohio is also an emerging battleground. As POWER reported on June 6, Crane told attendees at the Edison Electric Institute convention in San Diego that market design flaws continue to subsist, and changes are needed. “If we don’t focus on resiliency and national security, we could end up in a very dire situation,” he said, suggesting that the nation could not afford to see more nuclear plants retired.

Sites in jeopardy include Exelon’s Three Mile Island and FirstEnergy’s twin-reactor Beaver Valley plant in Pennsylvania, as well as FirstEnergy’s Davis-Besse and Perry plants in Ohio. FirstEnergy’s bankrupt competitive arm FirstEnergy Solutions (FES), which owns the company’s financially flailing nuclear plants, in March filed an application with the Department of Energy (DOE) urging the agency to direct PJM Interconnection to buy or arrange for energy, capacity, and ancillary services from certain coal and nuclear generators to maintain grid reliability. On June 5, FES told POWER that while the DOE’s leaked planmarked an “important first step, until timing and details of the order are clear, additional support at the state level will be necessary to protect the jobs in Ohio and Pennsylvania.”

Gifford and Larson posit that state “around market” actions “are alive and well,” and despite FERC’s activities, states will continue to seek to correct distressing “market” outcomes. “Thus, with each correction comes another intervention in the RAMMs deployed in PJM, ISO-NE, and NYISO.”

A More Pronounced Tilt Toward Renewables

Since 1999, when Wisconsin became the first state to enact a renewable portfolio standard (RPS), 28 other states have adopted regulatory mandates that require primarily investor-owned utilities to increase production of energy from wind, solar, and other renewable sources in lieu of fossil and nuclear electric generation, and a number of states, like Arizona, are considering strengthening their standards.

But in their white paper, Gifford and Larson say states are also creating “around market” solutions —via a prescribing replacement capacity approach. The approach says “build these assets,” as opposed to “subsidize these assets,” as with the maintenance-fee approach underscored by RPSs and ZECs. The authors point mainly to efforts by Massachusetts, whose governor in 2016 signed a bipartisan measure directing utilities to solicit and contract for 1,200 MW of hydropower and other renewables by 2022 and 1,600 MW of offshore wind by 2027 to fill the void left by the planned retirement of the Pilgrim Nuclear Plant in June 2019.

As part of that effort, the state selected the Northern Pass project, a controversial joint venture between Eversource and Hydro-Quebec to build a 192-mile, 1,090-MW high-voltage transmission line to bring Canadian hydropower through New Hampshire to Massachusetts. However, a New Hampshire panel in February denied the proposal over concerns it would hurt tourism. In March, the Massachusetts Office of Energy and Environmental Affairs said it would instead seek agreements with Avangrid subsidiary Central Maine Power for a 145-mile, 1,100-MW transmission line through Maine known as the New England Clean Energy Connect (NECEC) project. Early this May, however, four chairs of Maine Legislature’s Energy, Utilities, and Technology Committee expressed strong opposition to the $950 million proposal, saying it had no clear economic or climate benefits to Maine—even though a study commissioned by the Maine Public Utilities Commission showed the project could reduce annual carbon emissions as well as provide wholesale electricity benefits.

In tandem, Massachusetts appears to be making headway on the offshore wind front. On May 23, the state selected a partnership between Avangrid and Copenhagen Infrastructure Partners to develop an 800-MW offshore wind project off the coast of Martha’s Vineyard. Rhode Island on that same day awarded a 400-MW offshore wind procurement to Deepwater Wind. That week, New Jersey Gov. Phil Murphy also signed a law that commits the state to procure 3,500 MW of offshore wind.

The developments have been widely lauded as a boost for the fledgling sector, which has vast potential, but the sector’s growth could increasingly pressure profit margins of merchant generators in the Northeast, as POWER reported this April, citing projections by Moody’s Investors Service. “Like other renewable sources, [offshore wind’s] fuel and operational costs are significantly lower than those of conventional fuel generation assets and can bid into these premium wholesale markets at very low rates, depressing the attractive energy prices that existing participants have been enjoying. In addition, [offshore wind] has the potential to reduce capacity prices in the NE-ISO, NYISO and potentially within the PSEG capacity zone of PJM in New Jersey,” the credit rating’s service said.

The white paper’s authors note that Massachusetts’ experience shows barriers to the prescriptive replacement capacity approach, however. “Put simply, it is much easier to subsidize what already exists than start a string of fights about building something new. It bears watching whether this experience forecloses this ‘around market’ avenue and drives states toward the maintenance fee approach or even the vertical re-integration approach,” they say.

The Shadow of Vertical Integration

FirstEnergy competitive subsidiary FES sought legislative and regulatory relief for years before it filed for bankruptcy on March 31, and ultimately petitioned the DOE to prop up its nuclear and coal generators throughout PJM via an emergency action under Section 202(c) of the FPA.

FERC in April 2016 blocked power purchase agreements that would have supported continued operation of FirstEnergy’s Davis-Besse nuclear plant and the Sammis coal plant, as well as other plants in Ohio owned by American Electric Power (AEP), which the companies had argued were needed to ensure reliability and though the Public Utilities Commission of Ohio had blessed the deal just a month before. Since then, both AEP and FirstEnergy have shed assets in competitive markets in separate efforts to become a fully regulated companies. Duke Energy went that direction three years before, citing “volatile returns in the challenging competitive market in the Midwest.”

According to the EEI, the shift indicates a trend: In a February presentation to Wall Street, the trade group noted that in 2002, 52% of electric companies were regulated; in 2016, that number had surged to 69%.

For Gifford and Larson, exiting the merchant business represents an “ultimate ‘around market’” solution for FirstEnergy to vertically reintegrating its business. “The next question is whether its home state of Ohio follows suit,” they noted.

Lifelines for Gas Power

While the Trump administration’s leaked plan cites the proliferation of cheap gas as one factor that has rendered coal and nuclear generators uneconomic, natural gas generators, too—especially in California—are struggling to stay solvent.

California Independent System Operator (CAISO) is seeing an rapid expansion of renewables, continuing energy efficiency measures, and excess natural gas capacity. And though natural gas–fired power plants generated about half the state’s in-state power in 2016, natural gas operators like Calpine and Dynegy were recently forced to retire their Sutter and Moss Landing power plants, and NRG Energy in March announced it would close three gas plants owned by GenOn (which is soon to be an independent entity) in Southern California owing to “economic reasons.”

The state’s market, too, has been besieged by government intervention. Last fall, the California Energy Commission said it planned to reject NRG Energy’s proposed Puente natural gas plant because “feasible alternatives” that avoided or reduced environmental effects were available, forcing the company to withdraw its application. In January, state regulators voted on a proposal that would require Pacific Gas and Electric Co. to replace three natural gas plants owned by Calpine with energy storage and other carbon-neutral “preferred resources” like demand response.

The state’s urgency to pare down on natural gas mounted in 2016 after the leaking Aliso Canyon natural gas storage facility was shut down. California regulators are now considering a plan to shut down the Aliso Canyon facility in 10 years, and it will study that plan’s reliability implications for gas generators.

Reliability is already a sore point in CAISO: In its May 29–released 2018 Summer Reliability Assessmentthe North American Electric Reliability Corp. (NERC) said CAISO faced “significant risks” that could result in operating reserve shortfalls this summer, owing largely to lower hydro conditions and the retirement of 789 MW of dispatchable natural gas generation that had been available in prior summers to meet high load conditions.

According to the Gifford and Larson, an “‘around market’ solution for gas generators has not developed in California, nor is there any reasonable likelihood that the state will take such action.” Recent months have instead “seen gas generators turn to an old stalwart to stay online—the RMR contract.” The RMR construct—which is “essentially ‘around market’ before there was ‘around market’”—can be seen as an “‘in-market’ cousin of the maintenance fee approach used by the states in ‘around market’ contexts,” they said.

Gas generators in Texas, too, have felt the brunt of the renewables surge. Citing “historically low prices” and “challenging market conditions” in the Electric Reliability Council of Texas, Exelon generation subsidiary ExGen Texas in November 2017 filed for bankruptcy, handing four of its five natural gas–fired power plants in the state to lenders. The authors aren’t convinced that “around market” solutions could take hold in Texas, but they see a “clear” need for problems afflicting gas generation in the state, and suggest the state “may be the next battleground where regulators and market operators clash over the appropriate mechanism to achieve this end.”

The Push for “Resiliency”

FERC may have dealt a resounding rejection of the DOE’s proposed grid resiliency rule this January, but according to the white paper’s authors, the federal regulatory body is continually tweaking markets. That demonstrates markets are, at best, “a work in progress with significant limitations,” they said.

FERC, for example, recently issued orders to reform the limitations of price formation in markets “addressing uplift, settlement increments, and shortage pricing and offer caps,” they noted. Significantly, FERC’s recent actions as they concern reliability point to its position that “that out-of-market actions may be warranted in certain instances to address demonstrated reliability concerns.”

The docket FERC opened in response to the DOE’s grid resiliency proposal, for example, urged RTOs and ISOs to define and address resilience, “rather than looking at the at the fundamental question of whether the RAMM model met resilience and fuel diversity goals,” they said.

Grid operators appear to be divided on how to approach resiliency, though they are in agreement that solutions should be “in market.” PJM has taken the lead on these measures, implementing capacity performance reforms, and kicking off a study—Valuing Fuel Securityto determine what will be needed for a capacity market reforms to ensure its portfolio will perform in “realistic but extreme contingency scenarios.” Other grid operators—including ISO-NE and NYISO—appear opposed to the notion that FERC “should craft a universal standard or direct tariff charges,” the authors said.

But in-market actions aren’t just proliferating to address fuel security and resilience. NYISO, for example, at the end of April, issued a “straw proposal” to incorporate a carbon price into its market. ISO-NE, meanwhile, got FERC’s approval for a two-phase auction that compensates retiring units to allow state policy sponsored generators to replace retiring units’ capacity supply obligations. The reforms, known as Competitive Auctions with Sponsored Policy Resources (CASPR), “are an elaborate effort to preserve the illusion of fuel neutral markets in a state policy driven resource regime,” the authors said.

For now, the future of the market remains centered on FERC. The agency could embrace the Mystic RMR, and continue to seemingly unending stream of market solutions—effectively continuing to “pretend that these ‘electricity markets’ are functioning markets without severe problems and interventions coming from all directions,” Gifford and Larson said.

Alternatively, FERC could summon “extraordinary courage” to put an end to around market and in market “madness”—and “draw this line in the sand, especially given their recently restated ‘market’ conviction.”

—Sonal Patel is a POWER associate editor (@sonalcpatel, @POWERmagazine)