PJM stakeholders questioned whether a proposal addressing compensation for reactive power supply and voltage control service should be delayed because of several other important issues on which members are working.

Jim Davis, regulatory and market policy strategic adviser for Dominion Energy, provided a second first read of a problem statement and issue charge first presented at the Market Implementation Committee meeting in March. (See “Reactive Supply Compensation,” PJM MIC Briefs: March 10, 2021.) Davis said the “great discussion” on the issue at the MIC allowed Dominion to make changes to the issue charge.

PJM transmission customers pay for reactive power as an ancillary service under Schedule 2 of the tariff, and generation owners must submit a filing to FERC under Federal Power Act Section 205 to seek compensation. The existing rate mechanism is time-consuming for generation owners, developers and transmission customers, Davis said, exposing them to litigation costs in the defense or challenge of the requested rates.

Dominion proposed several key work activities in the issue charge, including studying the existing rate filing process, reviewing the inputs for determining revenues and examining the recovery mechanisms in other RTOs and ISOs. It also calls for discussing improvements to the cost recovery process and examining alternative mechanisms.

Some stakeholders requested that the key work activities include education and discussion to “identify potential gaming risks” for reactive power, Davis said. Dominion also added language to the issue charge that if gaming risks are identified, stakeholders would develop “protective provisions” to be included in a cost recovery mechanism.

Davis said stakeholders also questioned the timing of the issue, so Dominion extended the time for completion from June to August.

“We recognize there’s a lot on stakeholders’ plates these days,” Davis said.

Paul Sotkiewicz of E-Cubed Policy Associates asked how a generator could game reactive power.

Davis said there’s a concern that if a generation owner doesn’t like a rate that FERC approved or that the proceedings weren’t going in its favor, it could then elect to use the existing stated rate. “We thought that was a valid concern.”

Sotkiewicz said he recognized the importance of addressing the issue, but he wondered if it was the right time to take on extra stakeholder discussions because of pending FERC decisions and the significant work being done on the capacity market.

Michael Cocco, senior director of RTO and regulatory affairs for Old Dominion Electric Cooperative (ODEC), said he thought the issue charge would require any proposed solutions to create obligations on both buyers and sellers. Cocco said he didn’t think the proposal would provide the option for sellers to submit a Section 205 filing with FERC, essentially creating a potential floor rate.

ODEC was also concerned the issue may not be broad enough because it exempts existing generators who have reactive power service rates already submitted with the commission, Cocco said, and that the issue charge “seems to be limiting” discussions.

“We would want more of a market solution that looks at need and competition for these services,” Cocco said.

Davis said the intent was not to “prescribe a solution” in the issue charge, but to establish key work activities to have a “meaningful discussion” by all stakeholders to examine how the process works.

“We may not come to a solution, or we may come to something that’s very similar to ISO-NE,” Davis said. “In the end, if we decide that the existing methodology is appropriate, then so be it.”

Independent Market Monitor Joe Bowring reviewed an alternate problem statement and issue charge addressing the issue. The proposal largely mirrored Dominion’s language with some proposed additions.

Bowring pointed out that customers pay $355 million per year in separate reactive capacity charges and, currently, the costs of reactive are only partially integrated into the capacity market. He said 100% of the capacity costs of generating units are included in the cost of new entry, offset by a defined amount of reactive revenues, which is less than the levels currently paid, and that there is no reason to have a separate payment outside the capacity market.

Bowring said the Monitor wanted to point out some of the problems seen with the current process, make it “more efficient and more effective” and include the potential to recover capital costs related to reactive power through a market mechanism. He said stakeholders are spending a great deal of time and effort at FERC in “endless settlement conferences” regarding reactive power.

“It would be great to streamline that process,” Bowring said.

Dominion’s issue charge was “relatively noncontroversial,” he said, but the Monitor’s version aims to add clarity and more education on topics, including the fundamentals of planning for reactive capability and the coordination of planning with the competitive PJM market design.

Sotkiewicz said he had some objections to the language in the Monitor’s proposal. He didn’t oppose the proposed education, but he said many of the proposed issues for clarification “aren’t going to be clarified.”

“I think this goes a step too far and gets into the capacity market,” Sotkiewicz said.

Bowring said he doesn’t know why there would be objections to clarification of the issue and believes it “won’t take very long” to get some clarity in the issue by raising questions.

Sharon Midgley of Exelon said she felt the Monitor’s issue charge is “very broad” and “very comprehensive” and would be more time consuming to address. Midgley said there are other strategic issues members are working on, including the minimum offer price rule and energy pricing, that will take up valuable discussion time in the stakeholder process.

Midgley asked if Bowring thinks reactive power is a “top five” issue that stakeholders should be addressing this year or if it could be held off on.

Bowring said the Monitor has contemplated bringing the issue forward before but has chosen not to because of more pressing issues.

“We’re OK with putting it off for a while,” Bowring said. “I don’t think it makes sense to put it off forever, but fitting it in an appropriate spot of priority is fine with us.”

The committee will vote on the proposals at its May meeting.

Fast-start Pricing Manual Revisions

PJM presented the committee with an update on proposed manual revisions stemming from a FERC order late last year on fast-start pricing.

Nicole Militello, senior engineer of real-time market operations, provided a first read of updates to Manual 11: Energy & Ancillary Services Market Operations and Manual 18: PJM Capacity Market. Rebecca Stadelmeyer, manager of market settlements development, provided a first read of proposed changes to Manual 28: Operating Agreement Accounting.

FERC in December ordered PJM to make several changes to its tariff, including relaxing fast-start resources’ economic minimum operating limits and allowing resources to reflect their commitment costs in their prices. (See FERC Drops Fast-Start NOPR; Orders PJM, SPP, NYISO Changes.)

PJM responded to the order on Feb. 16, Militello said, requesting a response by this Friday. She said that if PJM receives a “clean” approval by then, it will implement the order on May 1 and conduct a second read of the manual changes in May at the MIC and the Markets and Reliability Committee meetings. If PJM doesn’t receive notification from FERC or has to make additional compliance filings, Militello said, the RTO will delay the second reading.

In Manual 11, PJM created new sections on fast-start capable resources, the fast-start capable adjustment process and eligible fast-start resources. In total, Militello said, PJM updated or created 21 sections in Manual 11 to provide clarity on how fast-start pricing will impact the current business rules.

Militello said Manual 18 had only minor changes, including a clarification that the scheduled megawatts used for excusal and bonus purposes in performance assessment interval settlement calculation will use dispatch run LMP.

Stadelmeyer said the Manual 28 updates include changes for dispatch differential lost opportunity cost credits and double counting of commitment costs.

Monitoring Analytics’ Catherine Tyler said the Monitor is “carefully reviewing” the manual changes, especially those for Manual 11. She said there are potential situations that may occur in which prices “don’t make sense given the outcomes happening in the market.”

Some of the changes in Manual 11 are “highly consequential,” Tyler said, including sections on verification of offers greater than $1,000/MWh and how reserves will be cleared and priced.

“There is a great need for clarity and transparency here because market participants are going to have questions once they see the different market outcomes with fast-start,” Tyler said.

Virtual Combined Cycles

Becky Robinson of Vistra provided a first read of a problem statement and issue charge addressing regulation for virtual combined cycle units.

Robinson said units that are “virtually” modeled by PJM can sometimes receive regulation awards from the market clearing engine that vary, which Vistra has been experiencing with some of its units.

The issue charge proposes several high-level work activities, Robinson said, including education on the operational and technical difficulties of operating virtually modeled combined cycle units with different regulation assignments and brainstorming possible solutions to ensure that regulation awards are consistent.

Robinson said Vistra wanted to scope the issue charge to be “targeted” because it’s a specific and technical issue.

“We don’t think of this as a broad policy issue,” Robinson said. “We don’t need to put another big item on stakeholder’s plates right now.”

The committee will vote on the proposal at its May meeting.