More than two dozen companies and coalitions filed responses to PJM’s March minimum offer price rule (MOPR) compliance filing last week, taking issue with the RTO on auction timing, floor prices, unit-specific rules and self-supply exemptions (EL16-49).

PJM made the 683-page filing in response to PJM Makes MOPR Compliance Filing.)

Below is a summary of the issues raised in the comments and protests filed last week.

Auction Timing

Commenters weighed in on both sides of PJM’s proposal to hold the Base Residual Auction for delivery year 2022/23, six and a half months after a final compliance order but no later than March 31, 2021.

The Electric Power Supply Association, PJM Power Providers (P3) Group, NRG Power Marketing and Calpine — whose complaint led to the December order — all called for an earlier auction.

“For its part, EPSA is deliberately refraining from wading into the details of the compliance filing in order to focus on the importance of conducting the 2022/23 BRA as soon as possible,” it said.

PJM proposed delaying the auction to as late as March 2021 if it is requested by regulators in a state that approves legislation before June 1 opting out of the capacity market for a fixed resource requirement (FRR).

EPSA noted that FERC’s April order rejecting rehearing of the December ruling requires PJM to make a second compliance filing June 1. “Realistically, even assuming a shortened comment period for the second compliance filing and a lightning quick turnaround on the commission’s part, it is hard to see the commission issuing an order earlier than July 1, 2020, which, under PJM’s schedule, would have the 2022/2023 BRA being conducted in mid-January 2021,” EPSA said. That would leave a forward period for the BRA of only 14 to 16 months, versus the three years under the Reliability Pricing Model’s (RPM) normal schedule.

“EPSA recognizes that PJM’s request may be moot if no state enacts FRR-enabling legislation by the end of this month, but the commission will undoubtedly be asked to extend the June 1, 2020, deadline or to deem it satisfied by something less than legislation ‘enacted’ by that date,” Calpine added. (Indeed, New Jersey regulators said the extension should also accommodate state regulatory processes. See below.)

P3 said the yearlong delay in the 2022/23 auction has already “thwarted” decisions on investments and maintenance; “projects have not been financed or refinanced” because of the lack of forward price signals.

“The delay … is well beyond the pale of acceptable. For the sake of suppliers, consumers and the sanctity of the PJM wholesale market, resumption of these auctions must become a priority for the commission and PJM,” it said. “PJM and the commission continue to look to each other to ‘make the call’ on the timing of the next auction. P3 urges the commission to end this back-and-forth and provide specific direction to PJM so these auctions can resume.”

P3 and NRG questioned whether PJM needs more than six months to prepare for the next auction, noting it proposed a 4.5-month time preparation period the subsequent BRAs.

P3 urged the commission to “settle the issue of the definition of a state subsidy” and finalize net cost of new entry (CONE) and avoidable-cost rate (ACR) values in its order on the compliance filing and give capacity resources 21 days to determine whether they are subject to the MOPR. “For those units that are considered subsidized and not eligible for an exemption, PJM and the [Independent Market Monitor] could immediately commence the unit-specific review process for those units that elect that process.

“PJM should not be idly waiting for the commission’s second order on compliance. Instead, the commission should direct PJM to commence its auction preparation following its approval in this compliance proceeding and then direct PJM, as part of the second compliance process, to derive a timeline shorter than six and a half months,” P3 said.

“Suspension of market milestones in deference to states embroiled in special interest lobbying does not simultaneously freeze all other factors that contribute to the economics of supply and demand of a 180,000-MW market, which serves 65 million customers,” NRG said.

The company said it has spent more than $500 million over the last six years to modernize and add environmental controls to its Illinois fleet “based on a market structure that was regularly generating price signals while at the same time enhancements such as Capacity Performance were being incorporated into PJM’s capacity construct.”

“Absent RPM price signals, NRG will blindly face investment decisions for commitment years that are rapidly approaching. Environmental regulators, both state and federal, will press on with deadlines that could require near-term capital spending for compliance with regulations such as the Effluent Limitations Guidelines for Steam Electric Generating Facilities and Coal Combustion Residuals.”

NRG and P3 also noted that utilities have had to adjust their default procurement programs because of the delay.

New Jersey electric distribution companies told the state Board of Public Utilities that bidders in the state’s Basic Generation Service default procurement program were likely to include risk premiums in their bids and that some potential bidders may not participate, “which could result in higher prices in the auction,” NRG said.

State regulators, consumer advocates and environmental groups argued in favor of the Organization of PJM States Inc.’s (OPSI) call to delay the auction until as late as May 2021, several of them noting that the coronavirus pandemic caused the suspension of state legislative sessions. The Maryland General Assembly adjourned March 18, failing to complete its full session for the first time since the Civil War.

“With the commission’s recent determination that capacity resources indirectly benefiting from state default service auction process are also subject to the MOPR, the impact of the MOPR on state policies has become only more disruptive, further supporting OPSI’s request,” the Natural Resources Defense Council, the Sierra Club and the Sustainable FERC Project said.

“The FRR alternative is not the only step that states might need to take to protect consumers and state policies from the harm of the MOPR,” the environmental groups said. “States may also need to revisit the structure of their default service auctions, the manner in which state objectives relating to generation are pursued or budgets for bill payment assistance.”

Exelon — which is supporting legislation to create an FRR in its Commonwealth Edison territory in Northern Illinois — also endorsed the May date. (See Clock Ticking on Exelon Illinois Nukes Under MOPR.)

In a joint filing, consumer advocates for New Jersey, D.C., Maryland, Delaware, Illinois and Pennsylvania said the auction schedule should allow for a “complete load forecast similar in scope and depth” to those used in prior auctions.

“The ongoing COVID-19 pandemic and attendant reduction in economic activity only highlight the need for regular updates over the coming BRAs,” the advocates said, noting that PJM’s load has dropped by an average of almost 8%, with peak impacts as high as 15%. “These significant reductions in demand will be all the more impactful because the time between the next four BRAs and the actual delivery year will be reduced from three years to as little as one year. In other words, updated load forecasts will reflect not just the long-term outlook but short- and medium-term operating conditions.”

The New Jersey BPU said PJM’s proposed extension should not be triggered only by FRR legislation. “Implementation of the FRR alternative could also involve efforts by state regulators and state regulatory processes — even where no change in legislation is required,” it said. “The [BPU], for example, has initiated an investigation into resource adequacy alternatives, which includes exploration of its own statutory authority to implement these changes without additional legislation.”

Demand Response

The PJM Industrial Customer Coalition called for Tariff changes to clarify that neither year-to-year fluctuations in customer consumption nor changes in state subsidy levels should cause an existing DR resource to lose its MOPR exemption.

The ICC said its proposed changes would “clearly distinguish between capability fluctuations that occur as a result of year-to-year modifications in consumption and the ‘step-jumps’ associated with uprates to physical capacity. The former is MOPR-exempt, the latter is not.”

Default Floor Prices

Members of the Maryland House Economic Matters and Senate Finance committees, which oversee state energy policy, complained that the default floors proposed by PJM will likely prevent many renewable resources, especially offshore wind and storage, from clearing the auction.

“The mere possibility that renewable energy and storage projects will be able to obtain resource-specific offer price floors allowing them to clear the auction does not allay states’ concerns,” they said. “The outcomes of such an idiosyncratic and opaque resource-specific offer floor process are unpredictable and therefore cannot be relied upon by state lawmakers that need to understand the costs and benefits of different legislative proposals.”

The Pennsylvania Public Utility Commission took issue with PJM’s use of “speculative” cost adders, saying MOPR floor prices “should not be ‘maximum offer prices’ but prices that reflect actual costs of competitive entry.”

It said PJM’s traditional price escalation factors are at odds with the declining costs of solar, batteries and onshore wind, noting new crystalline solar PV resources’ nominal levelized cost of energy have declined from $359/MWh to $41/MWh since 2009.

For onshore wind, PJM proposed using the Energy Information Administration’s 2019 value of $1,677/kW, which the PUC said is 14% higher than any alternative published value and outside Lazard’s range of values ($1,100 to $1,500/kW).

PJM’s gross CONE value for onshore wind assumes a 17-by-2.8-MW configuration (about 50 MW). “However, PJM’s current interconnect queue as of May 6, 2020, for onshore wind projects shows an average project size of 205 MW over 80 projects,” the PUC said.

“For newer declining cost technologies, annual price adjustments should be adopted to reflect current and projected nominal costs at the time of development,” it said.

Unit-specific Rules

PJM’s proposal for unit-specific exemption requests also drew criticism, with some calling for more flexibility and Calpine calling for rigorous vetting.

“The unit-specific review process must be carefully conducted in order to ensure that it does not defeat the purpose of offer-floor mitigation,” Calpine said. “PJM and the IMM should vigorously review any such submissions to ensure that the seller has adequately demonstrated that it is reasonable to assume an asset life of more than 20 years for the specific resource at issue. As another example, to the extent that a seller relies on ‘long-term power supply contracts, tolling agreements or tariffs on file with state regulatory agencies’ in order to support its projected energy and ancillary services markets revenues, PJM and the IMM should take pains to ensure that such contracts, agreements or tariffs are not disguised state subsidies.”

OPSI and the Pennsylvania PUC complained that although PJM said it would allow evidence of a longer than 20-year asset life, it proposed standardizing the other five financial modeling assumptions used to calculate resource-specific offers: nominal levelization of gross costs; no residual value; all project costs included with no sunk costs excluded; use of first year revenues; and weighted average cost.

“While each of the assumptions may have a material impact on the calculation of the offer floor, PJM only proposes flexibility with respect to the 20-year unit life element,” OPSI said. “If a resource owner maintains its financial records using real levelized costs rather than nominal, or can document residual value for its unit, or uses a different protocol for sunk costs, the resource-specific cost review process for the purpose of calculating MOPR floor prices should permit that flexibility to be reflected.”

State Procurements

Calpine also called for tightening PJM’s proposal for exempting state default service procurements.

It said the state subsidy definition should only exempt “nondiscriminatory, competitive, and fuel- and emissions-neutral state-directed default service procurement programs.”

“Without this modification, the proposed definition could allow a state to evade the MOPR by requiring a procurement process that is nominally competitive and neutral with respect to fuel type but that is structured in a way that will exclude potential competitors for the benefit of favored resources,” Calpine said.

Self-supply

Dominion Energy called for broadening the competitive exemption to include self-supply entities.

“Self-supply entities that are vertically integrated utilities, such as Dominion Energy Virginia, currently own and are developing new solar resources [that] are not part of its rate base and whose costs are ‘ring fenced’ and not recovered from ratepayers,” it said. “As a result, these resources are not receiving a ‘state subsidy’ as defined by the Dec. 19 order even though they are owned by a ‘self-supply entity.’”

OPSI called for exempting all existing bilateral contracts, saying PJM’s proposal discriminates against load-serving entities in restructured states.

The organization said it supports PJM’s proposal to exempt bilateral contracts where the buyer is a self-supply entity but said the RTO’s “justification for the exemption applies equally to other, bilateral contracts of non-self-supply entities.”

“This exemption should be extended further to include enforceable supply purchase contracts entered into by non-self-supply entities entered into prior to Dec. 19, 2019, in reliance upon then-existing commission guidance. Load-serving entities in restructured states should not be precluded from using the business arrangement provided for self-supply entities in PJM’s compliance filing.”

Voluntary RECs

The Advanced Energy Buyers Group, a coalition of large energy users, said FERC should order PJM to create “an additional pathway” for capacity resources that sell a portion of their output to a voluntary purchaser and a portion to a compliance purchaser to avoid applying the expanded MOPR to the voluntary transaction.

“PJM’s compliance filing would subject such projects to the MOPR in their entirety. That result could also limit the market for voluntary purchases of renewable energy by forcing buyers to purchase the entire output of a project to avoid the MOPR, which many buyers may not be in a position to do,” the group said.

Subsidy Determinations

The American Wind Energy Association, the Solar Energy Industries Association, Advanced Energy Economy and the Solar Council, filing jointly as “Clean Energy Associations,” asked the commission for assurances that capacity market sellers “will be allowed to rely upon guidance from PJM and the IMM” in determining which state and local programs constitute state subsidies. They urged FERC to “direct PJM to create an ongoing process for market participants to timely obtain such determinations.”

The NRDC, Sierra Club and Sustainable FERC Project called for a transparent process, including a public list of which policies have been determined to be subject to MOPR; a process for parties to submit a policy for consideration with timelines for the decision-making process; and a process for determinations to be clarified or challenged at FERC.

“Absent clear reporting requirements, expanded discovery powers for PJM and/or the Market Monitor, and possibly some form of safe harbor for resource owners, uncertainty regarding the ultimate purchaser of power is likely to result in over mitigation of resources that do not receive a subsidy but are unable to verify they do not,” the groups said.

“This kind of uncertainty, case-by-case analysis and lack of transparency or oversight is likely to result in inconsistent application of the MOPR in a manner that introduces discriminatory treatment of resources.”

American Electric Power complained that PJM’s proposed MOPR exemption for voluntary bilateral transactions was unduly restrictive. FERC said voluntary bilateral transactions were not state subsidies but “permissible out-of-market revenue.”

“PJM appeared to limit the applicability of the commission’s holding in its March compliance filing by only addressing its treatment of bilateral transactions in which one party is a self-supply entity,” AEP said.

Accounting for Federal Tax Credits

AWEA and SEIA also said that while PJM properly proposed accounting for the federal investment tax credit in default gross CONE calculations for wind and solar resources, it “does not expressly provide comparable treatment for other types of federal subsidies,” such as the federal production tax credit.