By Christen Smith and Rich Heidorn Jr.

Old Dominion Electric Cooperative, which supplies power to 1.4 million people in Virginia, Maryland and Delaware, has been generating its own power since 1983, when it bought a share of Virginia Electric and Power Co.’s North Anna Nuclear Power Station.

It would add the 433-MW coal-fired Clover Power Station in 1995/96, and more than 1,600 MW of natural gas capacity in 2001-2004. Less than two years ago, it began operating the 1,000-MW Wildcat Point combined cycle plant. As a result of its investments, it got 64% of its energy and 88% of its capacity from its own assets in 2018.

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Attack on Business Model

ODEC and other self-supply load-serving entities (LSEs) argue the order will unravel their business model and undermine their roles in local economic development. The National Rural Electric Cooperative Association (NRECA) and East Kentucky Power Cooperative (EKPC) called the expanded MOPR a “frontal attack” on practices used by cooperatives for decades.

“The longstanding business model of electric cooperative LSEs is to invest in generation for their long-term load obligations, not the short-term forward capacity construct,” ODEC said in its Jan. 21 rehearing request (EL16-49, EL18-178). “Therefore, capacity which might be excess to an LSE’s reliability requirement in the early years of a resource will decline in later years as load grows. This does not make the investment ‘uneconomic.’” (See PJM MOPR Rehearing Requests Pour into FERC.)

ODEC joined PJM in 1998 to aid in the delivery of power to its three member distribution cooperatives on the Delmarva Peninsula. But its wholesale power contracts (WPCs) with all of its 11 members have been on file with FERC as far back as 1992.

“Most if not all of these [WPCs] originated well before PJM’s capacity construct and MOPR” in 2006, the National NRECA and EKPC said in their own rehearing request.

Their filing referenced the Supreme Court’s 2016 ruling in Hughes v. Talen, which said states were free to subsidize new generation “through measures untethered to a generator’s wholesale market participation.”

“There can be no legitimate conclusion that the WPCs are directed at or tethered to the operation of generating resources in PJM’s capacity construct,” NRECA and EKPC said.

Economic Development Threatened

EKPC, which joined PJM about seven years ago, said it signed on “to bring the benefits of a competitive wholesale market” to its 16 member co-ops in Kentucky. “These benefits have made it possible to attract new commercial and industrial customers to locate in Kentucky,” it said.

EKPC said its economic development efforts are threatened by the expanded MOPR, which also appears to cover new demand response resources and renewable generation with voluntary renewable energy credits (RECs). EKPC filed a “green tariff” proposal with the Kentucky Public Service Commission in 2019 in response to increased customer interest in “renewable or sustainable” resources.

“The application of the MOPR to resources supporting voluntary clean energy initiatives may discourage new industries from locating in the PJM region of Kentucky despite the great efforts EKPC is making to advance economic development in the commonwealth of Kentucky,” EKPC said. “The December 2019 order may frustrate EKPC’s opportunity to court new industries seeking to ensure that their energy needs are met with renewable resources.”

EKPC, which sells DR from nine end-use customers into the capacity market, said one industrial load has invested millions to increase its DR capability. EKPC included the expansion in the DR plan for the 2022/23 Base Residual Auction, which has not been held because of the MOPR litigation. “It is unclear whether that capability will be considered to be existing and eligible for the exemption provided in the December 2019 order,” EKPC said.

No Longer ‘Residual’ Market

FERC approved PJM’s Reliability Pricing Model (RPM) and its BRAs in 2006 to procure capacity “after LSEs have had an opportunity to procure capacity on their own” and “as a last resort.”

EKPC said FERC’s ruling was “the most drastic and likely most destructive measure taken by the commission to date” in its attempt to transform PJM’s “resource adequacy market away from a residual capacity auction … to a mandatory sole source for PJM and its LSEs to meet regional capacity obligations.”

“The chilling effect this order will have on investment in new self-supply resources will convert PJM’s capacity market from a ‘Base Residual Auction,’ designed to procure capacity not otherwise procured through self-supply, to an auction in which capacity purchases from the market will be the only viable option for all LSEs, thus eviscerating the self-supply option,” North Carolina Electric Membership Corp. said in its rehearing request.

Expanding MOPR to public power self-supply resources is based on the “mistaken premise that all resource entry and exit must be coordinated solely by the RTO-administered market to be deemed economic,” consultant Marc D. Montalvo said in comments filed on behalf of the American Public Power Association (APPA) during the commission’s paper hearing on the docket.

“RPM is a mandatory resource adequacy construct that offers a single product, and ‘competitive’ prices are determined by PJM applying cost development guidelines with no empirical link to actual market conditions or consumer decisions,” said APPA, American Municipal Power (AMP) and Public Power Association of New Jersey (PPANJ). “Ironically, by its latest action, the commission has removed any remaining genuine market component of RPM by requiring all ‘competitive’ offers to be determined administratively in Valley Forge, Pa.”

MOPR History

The MOPR was introduced along with RPM in 2006. It does not apply to baseload resources that required more than three years to develop (nuclear, coal and integrated gasification combined cycle facilities), hydroelectric facilities, or any upgrade or addition to an existing generator. Also exempt was any new entry being developed in response to a state regulatory or legislative mandate to resolve projected capacity shortfalls for the delivery year.

In 2011, FERC approved revisions eliminating the state mandate exemption and adding a unit-specific review process to consider cost justifications submitted by resources whose sell offers fell below the established floor. Wind and solar facilities were also added to the list of resources permitted to make zero-priced offers; additions to existing capacity resources were no longer exempted.

In 2013, FERC approved a categorical exemption for self-supply for public power and vertically integrated utilities, subject to net-short and net-long thresholds. The commission also agreed to exempt “competitive entry” units that could prove they received no out-of-market funding other than that resulting from competitive auction.

But in 2017, the D.C. Circuit Court of Appeals remanded the 2013 order, saying the commission had exceeded its authority in modifying PJM’s proposal by retaining the unit-specific review process, which the RTO had wanted to eliminate. (See PJM MOPR Order Reversed; FERC Overstepped, Court Says.)

The commission responded by returning to the market design in effect before the 2013 MOPR proceeding, which applied the MOPR to all new, nonexempted gas fired resources but allowed zero-priced offers by nuclear, coal, wind solar and hydro. (See On Remand, FERC Rejects PJM MOPR Compromise.)

That set the stage for the commission’s June 2018 order, which declared the MOPR unjust and unreasonable for failing to address price suppression from growing state subsidies for nuclear and renewable resources. (See FERC Orders PJM Capacity Market Revamp.)

FRR not an Option

FERC said self-supply entities “remain free” to provide for their own resource adequacy through the existing fixed resource requirement (FRR) alternative.

But APPA, AMP and PPANJ say that neither the FRR option nor the unit-specific review process is a “reasonable accommodation” for self-supply.

They cited a 2014 ruling by the 3rd U.S. Circuit Court of Appeals that “participating in the FRR option is an all-or-nothing proposition and appeals as a practical matter only to large utilities that still follow the traditional, vertically integrated model.”

Public power LSEs’ capacity needs can change over time as they add new members, if new locational deliverability areas (LDAs) are added or their boundaries change, the groups noted. “The creation of a new binding Cleveland LDA could impact 100% of the municipality’s load, whereas only a portion of the load of FirstEnergy, would be impacted,” they said.

“The FRR may not be a workable alternative for smaller LSEs, given the requirements to opt out of the capacity construct for both purchases and sales, for a five-year period with onerous financial consequences if the ability to do so becomes untenable,” ODEC said.

The unit-specific exemption only offers an alternative to the default offer floor, APPA, AMP and PPANJ said. Resources using the unit-specific exemption must still bid above an administratively determined level, leaving them at risk of not clearing the auction.

They cited the example of Delaware Municipal Electric Corp. (DEMEC), which was required to use a unit-specific exemption to qualify a then-new gas-fired generator in 2011 for the 2014 BRA. They said PJM’s Independent Market Monitor sought to add 200 basis points to DEMEC’s actual financing rate. After negotiations, DEMEC and the Monitor agreed to a mitigated offer “substantially” higher than what the company had planned to bid.

“Fortunately, DEMEC’s offer price for the new resource did clear the 2014 BRA. However, had DEMEC acceded to the IMM’s original proposed upwardly mitigated offer price, DEMEC’s generation resource would not have cleared the 2014 BRA, thereby stranding DEMEC’s investment and causing irreparable harm to DEMEC and its communities,” the groups said.

EKPC said it and other co-ops have been snared in a catch-22.

“Since the commission broadly swept the cooperative electric utility business model into the definition of state subsidy, it is not clear how an electric cooperative could certify that it is foregoing receiving the state subsidy in order to take advantage of the competitive offer exemption,” it said. It asked the commission to clarify how PJM should apply the competitive exemption to co-ops. It also sought rehearing of the commission’s determinations that voluntary RECs are state subsidies and that the MOPR should apply to DR.

“Regardless of the characterization of the MMU’s actions in a prior 2011 MOPR review, the MMU reviews unit specific MOPR requests under the existing rules based on unit specific details, including the cost of capital,” IMM Joe Bowring said in response. “The MMU has always respected the public power business model and recognizes that the cost of capital for public power entities is not the same as it is for private entities. The commission, in [the December] order, has not stated that the financing options of public power entities constitute a state subsidy.”

Fear of ‘Balkanization’

EKPC said blocking vertically integrated utilities from seeking a competitive exemption for future resources “will have a negative impact on the existing market and will hamper future prospects of growing the PJM wholesale market to include new territories.”

“Given the 10 cooperatives and three vertically integrated utilities that currently participate in the capacity market, EKPC is concerned about the potential for balkanization in the PJM region if many or all of these entities utilize the FRR alternative as the better way to satisfy their load-serving obligations.”

The Brattle Group had expressed similar concerns in a 2011 report for PJM, saying that not clearing self-supplied resources would “make it more difficult and costly to hedge capacity prices and will likely force many load-serving entities that rely on self-supply to opt out of RPM through the FRR option. More widespread use of the FRR option would reduce market efficiency and increase costs.”