By Christen Smith and Rich Heidorn Jr.

VALLEY FORGE, Pa. — PJM officials said Wednesday that they won’t run a capacity auction until FERC approves the RTO’s compliance filing implementing the expansion of its minimum offer price rule (MOPR), making it unlikely the delayed 2019 auction will occur this year.

PJM must make a compliance filing by March 18 in response to FERC’s 2-1 ruling expanding the MOPR to all new state-subsidized resources.

“We do not plan to run a [Base Residual Auction] until we have an approval of that compliance filing. There’s so much at stake. … It is extremely risky for us to do that, and it’s a little bit too much risk for us to take on,” Adam Keech, vice president of market services, told the Market Implementation Committee during the first stakeholder meeting on MOPR since FERC’s Dec. 19 order. (See FERC Extends PJM MOPR to State Subsidies.)

PJM’s Pat Bruno indicated later that an auction before year-end was unlikely although it was “technically possible.”

Noting that FERC rejected most of PJM’s proposals, Keech also said the RTO is likely to file a request for rehearing or clarification of the order for its “procedural value.” Rehearing requests are due Jan. 21.

“We want to make sure we’re not marginalized in ongoing proceedings,” General Counsel Christopher O’Hara explained, highlighting the possibility that the order will be the subject of an federal appellate court proceeding.

“It’s going to be near impossible for the commission to accept the compliance filing without also granting at least clarification in part, and perhaps some of those clarifications cross over into rehearing,” O’Hara added. “I’m not talking major issues; I’m talking about some smaller issues.”

Wednesday’s meeting also marked the first public appearance by PJM’s new CEO, Manu Asthana, who began work last week. Asthana, who spoke briefly at the beginning of the MOPR discussion, said he and other board members want to incorporate stakeholder feedback in the compliance filing.

“We want to listen to … your perspective on the order: what it means for your business and what you want us to do about it,” he said.

Stakeholders: Resume BRA ‘ASAP’

The five-and-a-half-hour MOPR discussion also featured presentations by more than a dozen stakeholders who gave varying interpretations on the impact of the order and how PJM should respond.

Calpine — which filed the complaint that led to the commission’s June 2018 order finding the existing MOPR not just and reasonable — called for swift scheduling of the 2019 BRA. (See FERC Orders PJM Capacity Market Revamp.)

“There is nothing to debate. FERC issued its order, an order we have been waiting for over a year, and it’s time to proceed,” Calpine said. “Eighteen months have passed, and it is now PJM’s responsibility to hold the auction as soon as possible.”

The PJM Power Providers group agreed, saying the BRA should be resumed “ASAP.” The American Petroleum Institute, which represents both natural gas producers and large energy users, called for “a timely restart” of the BRA “and a clear signal of future regular auctions.”

But American Municipal Power, which owns and operates generation, transmission and distribution for municipal utilities in nine states in PJM and MISO, said the RTO should seek an extension of the 90-day compliance filing deadline.

AMP said the additional time would allow PJM to use a “transparent” process to craft a response that could minimize further litigation and uncertainty.

Exelon said PJM should set the 2022/23 BRA about 12 months after the compliance order to allow state regulators and legislators time to make rule changes required if they decide to exit the capacity market and develop fixed resource requirements (FRR) as an alternative method of resource adequacy.

Exelon’s Jason Barker said PJM that must “offer a meaningful opportunity for states to consider and pursue alternatives” to the RTO’s capacity procurement.

“FERC has provided the states with a binomial choice for shaping the capacity mix to achieve their environmental goals: participate in the PJM capacity market — which does not value environmental attributes — or direct their utilities to establish an FRR.”

Jeff Dennis, general counsel for Advanced Energy Economy, whose members include renewable generators and companies providing demand response and energy efficiency aggregation, said it’s likely PJM will need to postpone the 2020 auction as it did the 2019 BRA. A former FERC official, Dennis told an AEE webinar on the MOPR ruling Wednesday: “We are likely many, many months away from a capacity auction.”

Disagreement over RGGI

The speakers gave differing views on whether the commission’s definition of state subsidy would impact the resources of states participating in the Regional Greenhouse Gas Initiative.

Keech said PJM may seek FERC clarification on how RGGI and New Jersey’s Basic Generation Service (BGS) Electricity Supply Auction are impacted by the MOPR expansion.

In his dissent on the December order, Commissioner Richard Glick said the commission’s subsidy definition was likely to snare the BGS auction, in which electric distribution companies seek offers from resources to serve their load. That would require PJM and its Independent Market Monitor to “look behind the results of every BGS auction to determine which resources are receiving a benefit from this state process,” Glick said. “Even state processes that are open, fair, transparent and fuel-neutral may be treated as state subsidies, irrespective of the underlying state goals.”

“We’re not quite clear how those [programs] fit inside the … definition of a state subsidy,” Keech said. “Without more detail, it would seem like it would fall under state subsidy.”

Exelon said PJM’s compliance filing “should clarify that RGGI does not confer an actionable subsidy to any resources.”

Vistra Energy agreed, saying that although FERC’s subsidy definition is very broad, “we think it’s possible to implement it reasonably without implicating market-driven price outcomes” such as the RGGI carbon auctions.

The Advanced Energy Management Alliance said PJM should not consider DR as state-subsidized, saying “FERC precedent is to not include state peak shaving programs as subsidy.”

AMP made a similar pitch for the public power business model, citing what it called the “fallacy that tax-exempt financing constitutes a subsidy.” It called for a new stakeholder process to revise the RTO’s unit-specific exemption rules, saying PJM and the Monitor lack first-hand experience with the public power business model, “leading to incorrect comparisons of financing related costs for merchant projects and those available to not-for-profit public power organizations.”

The American Wind Energy Association and Solar Energy Industries Association said the unit-specific exemption process “must be flexible so all resource types … reflect their actual project costs, operations and projected revenues” and not be based solely on criteria used for setting the net cost of new entry for gas-fired generation.

Impact on Renewables, RECs

There also was discussion on FERC’s ruling to not differentiate voluntary renewable energy credits (RECs) from state-mandated RECs and disagreements over the impact the ruling will have on future renewable resources.

FERC said that although it saw no need to apply the MOPR to “voluntary, arm’s length bilateral transactions … it is not possible, at this time, to distinguish resources receiving privately funded voluntary RECs from state-funded or state-mandated RECs because resources typically do not know at the time of the auction qualification process how the REC will be eventually used.”

Vistra said voluntary RECs should not be considered subsidies. The company said it backs its renewable energy retail products with more RECs than needed to comply with state mandates. “MOPRing these purchases will mean that it is more expensive to offer these ‘green’ products to our customers, there will be fewer low carbon resources to source from than robust market dynamics alone would support, and there is an efficiency loss.”

Lightsource BP, a utility-scale solar developer with more than 1 GW of projects in the PJM interconnection queue, said voluntary RECs should not be considered state subsidies because they are a separate market from mandated RECs and trade at a fraction of solar compliance RECs.

It said vintage 2020 voluntary RECs are currently trading at 50 cents to $1/MWh, while solar RECs in New Jersey are worth about $227.50/MWh, $80/MWh in Maryland and $40/MWh in Pennsylvania. “As such, estimated project revenues from voluntary REC sales pale in comparison to estimated project revenues from state compliance RECs and should not be considered material,” Lightsource said, adding that PJM should mandate that capacity sellers use REC tracking systems to provide transparency to address FERC’s concerns.

“Forecasted PJM capacity market revenues are an integral component of PJM solar financeability, and a majority of the 1 GW in our PJM portfolio is at risk for being priced out of the capacity market auction,” Lightsource said.

But LS Power said the order would not impact its investments in intermittent resources because they don’t rely on the capacity market for significant revenues. It noted that wind and solar resources comprise only 1.2% of PJM’s capacity requirement. It said a 10-MW solar plant in New Jersey would see 80% of its revenues from RECs ($3 million), with energy market revenues contributing another $500,000 and capacity revenues adding only $250,000 (6.7%), assuming the market clears at $150/MW-day.

“Capacity is not the driving revenue stream for investment the way it is for other units needed for reliability that are dispatchable and flexible,” LS Power’s Marji Philips said. “PJM’s responsibility is making sure that plants that do rely on the competitive market that PJM also relies on for reliability have the appropriate price signals.”

Eliminate Capacity Market?

The Natural Resources Defense Council’s Sustainable FERC Project said the MOPR ruling “threatens to make PJM irrelevant” to states’ efforts to reduce carbon emissions.

It noted that 10 of PJM’s 13 states and D.C. have renewable portfolio standards, with D.C., Maryland and New Jersey having set or proposed 100% clean power goals, while three have laws supporting nuclear power.

“PJM should request rehearing and, if denied, seek appellate review of the MOPR order,” it said.

It also said PJM’s planning parameters should be changed to reflect the reliability value of uncleared capacity and that the RTO should ultimately retire the capacity market and develop an alternative resource adequacy structure.

PJM said it would post answers to stakeholders’ questions and hold a second stakeholder discussion on the ruling on Jan. 28. Questions can be submitted to RPM_Hotline@pjm.com.