Imports/Exports Top Talk at NYISO Carbon Pricing Kick-off

By Michael Kuser

RENSSELAER, N.Y. — The NYISO working group charged with shepherding carbon pricing into New York’s wholesale electricity market kicked off its efforts Tuesday by taking up the issue of how import and export transactions would be handled under the pricing scheme.

A task force created in October 2017 by NYISO and the New York State Public Service Commission worked for more than a year developing a proposal to price carbon into wholesale markets. Last month, it turned the proposal and final details over to the ISO’s stakeholder process. (See IPPTF Hands off Carbon Pricing Proposal to NYISO.)

Ethan D. Avallone, NYISO senior energy market design specialist, sho w e d the Market Issues Working Group (MIWG) several hypothetical transactions, pointing out that his examples “had to be extreme to show the effects of under- or overestimating the real-time carbon charge.”

A carbon charge or credit would apply only to transactions that actually flow in real time, and to external transactions such that they compete with internal resources and each other as if the ISO was not applying a carbon charge to internal suppliers — that is, on a status quo basis, Avallone said. (See NYISO Plan Revises Treatment of Carbon-Free Resources.)

A market participant intending to import into the New York Control Area (NYCA) will sell power at the proxy generator bus for the applicable control area in the NYISO market. | *NYISO*

To calculate locational-based marginal prices, the examples in the presentation focused on prices at one NYISO proxy generator bus located outside the New York Control Area to represent a typical bus in an adjacent control area. There may be more than one proxy generator bus at a particular interface with a neighboring control area to enable the ISO to distinguish the bidding, treatment and pricing of products and services at the interface.

Imports into the NYISO market are paid the proxy generator bus price for the applicable external control area. For example, an import with costs of $40/MWh in the PJM market could sell at the $50 PJM Keystone Proxy Generator Bus price in the NYISO market for a potential net revenue of $10/MWh.

Several stakeholders at the meeting said they wanted better real-time data from the ISO, possibly using a unit-specific, rather than aggregated, approach.

“The reason we landed on this more aggregated approach is because we wouldn’t be able to tell whether a unit-specific one is representative,” Avallone said, adding that the fundamental question about what approach to take had been fully aired in the stakeholder process last year.

Seth Kaplan of EDP Renewables, the largest wind generator in the state, said his company had no position on the matter but suggested the ISO ask for market proposals for a unit-specific approach from those who were advocating one.

Howard Fromer, director of market policy for PSEG Power New York, offered that the ISO could provide day-ahead carbon data to help traders to better ascertain the right carbon adder in order to plan their bids.

“We would settle on the real-time LBMP,” Avallone said in explaining the ISO’s choice not to provide day-ahead data. “We have discussed recalculating LBMPs for a historical time period as if there were a carbon component [c] included [in order] to get an approximation of LBMPc in real time.”

Michael DeSocio, the ISO’s senior manager for market design, said energy traders were already “using some model, some heat rate model. Now you just have to add in a carbon adder, so it’s not much different from what you do today.”

Fromer said it would take some time to digest the detailed examples, and that his company wants to see carbon pricing move ahead, but it’s “likely to have some impact on scheduling” as traders are “being forced into guesstimating on the day-ahead LBMPc.”

Scott Leuthauser, manager of regulatory affairs and business development for H.Q. Energy Services (U.S.), read a prepared statement saying his company opposes applying the carbon charge, as proposed, to external transactions because it creates additional risks for them. External resources have no control over NYISO carbon emissions and no way of physically hedging against the risk, he said.

“As we have said before, it is better for traders to assess and bear the risk,” Avallone said.

The MIWG next meets Jan. 22 to review Tariff sections impacted by a carbon adder.

New Zone J Operating Reserves

NYISO is speeding up the stakeholder process in order to implement by June a Zone J (New York City) reserve requirement and procure 500 MW of 10-minute reserves and 1,000 MW of 30-minute reserves, the MIWG learned Tuesday.

Ashley Ferrer, NYISO energy market design specialist, tol d the working group that creating a Zone J reserve region and associated reserve requirements can provide more efficient scheduling and procurement of resources, as well as location-specific market price signals.

The ISO is considering the appropriate operating reserve demand curve for the zone’s reserves and will present its proposed pricing as part of further discussions regarding the proposal, Ferrer said.

NYCA operating reserves with Zone J | *NYISO*

Establishing a separate Zone J operating reserves requirement was originally recommended in the 2017 State of the Market report and later in the 2018 Management Resp o nse to an assessment by Analysis Group of wholesale market options regarding performance assurance.

The ISO will present market design and associated Tariff revisions to stakeholders this month and next, with the Business Issues and Management committees slated to vote on the proposal in March. Assuming stakeholder approval, the ISO would submit the proposal to the Board of Directors in April and file Tariff revisions with FERC seeking approval to implement in June.

January 16, 2019

CAISO Finalizes 32 RC Agreements

By Hudson Sangree

CAISO said Monday it had finalized agreements to provide reliability coordinator services, starting later this year, with 32 transmission operators and balancing authorities in the West.

The ISO expects to eventually have a total of 39 RC clients. Those that have finalized agreements include the Bonneville Power Administration, Arizona Public Service and PacifiCorp. (For a complete list, see CAISO ’s website.)

“We are pleased with the progress made this past year to offer Reliability Coordinator services, and welcome our new participants,” CAISO President Steve Berberich said in a news release. “After a year of intensive planning and coordination, the ISO will now focus on developing technology and integrating systems to meet our July 1 implementation date.”

Transmission towers stand near The Dalles Dam, operated by the Bonneville Power Administration, one of 32 entities with which CAISO has signed agreements to provide reliability coordinator services starting this year. | © *RTO Insider*

CAISO said it is moving forward to complete the NERC certification process led by the Western Electricity Coordinating Council (WECC).

CAISO won the majority of Western clients for its RC services after Peak Reliability decided last year to wind down its reliability coordinator services by the end of 2019. Peak is currently the RC for nearly all of the Western United States and parts of Canada and Mexico. (See R C Transition, California Wildfires Will Occu p y 2019.)

Peak stunned the electricity sector in July when it announced it would end its RC role and withdraw from its effort to develop a regional electricity market competing with CAISO. (See Peak Reliability to Wind Down O p erations.) The Vancouver, Wash.-based company said it would shut its doors as early as Dec. 31, 2019, after transitioning its customers to other RCs.

Several months before the announcement, CAISO, a Peak RC customer, said it would “reluctantly” leave Peak, develop its own RC services and offer them to others at reduced costs. CAISO’s move was seen as a reaction to Peak entering a partnership with PJM to form a Western RTO to compete with the ISO’s expansion.

CAISO, SPP and BC Hydro decided to fill the role left behind by Peak. Most of the Western Interconnection signed nonbinding letters of intent to take advantage of CAISO’s RC services. (See CAISO RC Wins Most of t he West.)

In November, FERC approved a set of Tariff revisions covering CAISO’s new RC services, clearing the way for about 72% of the region’s load to sign on with the RTO, compared with 12% for SPP. BC Hydro is proceeding with plans to provide RC services for its own territory in British Columbia, representing about 7% of load in the region overseen by the Western Electricity Coordinating Council.

The transition of RC services is scheduled to be phased in this year, with CAISO assuming responsibility for California and part of northern Mexico on July 1. BC Hydro will become the RC for a large swath of western Canada on Sept. 2. CAISO will then take over RC services for many areas outside of California on Nov. 1, while SPP will take responsibility for other regions of the West on Dec. 3.

January 16, 2019

Carias, Buffington Smoothly Assume MOPC Leadership

By Tom Kleckner

NEW ORLEANS — For a historic moment for SPP, the ascension of two women to the RTO’s Markets and Operations Policy Committee leadership was fairly low-key.

NextEra Energy Resources’ Holly Carias began her term as MOPC chair Tuesday by simply saying, “Thank you for letting me be the MOPC chair.”

Then it was down to business for NextEra’s director of regulatory affairs. She ran the meeting efficiently, wasting no time in moving from agenda item to agenda item. She conducted the votes quickly and brought the committee back on time from breaks.

NextEra’s Holly Carias (center) opens the January MOPC meeting as SPP’s Lanny Nickell and KCP&L’s Denise Buffington listen. | © *RTO Insider*

“I’m glad to see you in a leadership position,” Jim Eckelberger, SPP’s chairman emeritus, told Carias during the lunch break.

Board Chair Larry Altenbaumer offered his own unsolicited comments during the opening introductions. “I think it’s a good leadership team,” he said.

Serving as MOPC’s vice chair is Denise Buffington, director of federal regulatory affairs for Kansas City Power & Light. She and Carias are only the second and third women to take a leadership position at MOPC.

Asked if two women leading a male-dominated group — as is typical in the electric industry — is a good sign for women, Buffington replied unequivocally, “Yes!”

“Obviously, I’m excited for the opportunity to take a leadership role at the board level,” she said.

Diversity and Balance

Whereas SPP made a concerted effort to increase the diversity of its Board of Directors by adding two women as members last year, SPP Vice President of Engineering Lanny Nickell said that was not the case with the MOPC appointments.

“I don’t think the Corporate Governance Committee recommended Holly and Denise to serve as MOPC chair and vice-chair, and the board approved that recommendation, to increase diversity,” said Nickell, himself a new addition to MOPC as staff secretary. “The recommendation was made because these were the two best candidates for the positions.”

Both positions opened up late last year when Chair Paul Malone cycled off and Vice Chair Jason Atwood left Northeast Texas Electric Cooperative. Having already sent out one solicitation for vice chair, SPP sent out a second for chair or vice-chair.

NextEra’s Holly Carias chats with SPP’s Antoine Lucas before the MOPC meeting begins. | © *RTO Insider*

If anything, the board and CGC followed an unwritten rule in ensuring the MOPC chairs represented either a transmission user (Carias) or transmission owner (Buffington). As an added measure, Carias is also the first independent power producer representative to chair MOPC since Dogwood Energy’s Rob Janssen.

“Certainly, diversity of thought and skill sets and experience is important,” Nickell said. “If you look at the history of chairs and vice chairs of MOPC, you’ll note there has been an attempt to have a balance of perspectives.”

Nickell said Carias is a collaborator who tries to find creative solutions “that tend to serve the interests of a broad group of parties.”

“She seems to have SPP’s regional interests in mind when she participates in our stakeholder discussions,” he said.

And Buffington?

“She’s very passionate,” said Nickell. “She’s very good at asking the right question to get [to] the root cause of an issue. She makes us think about what we can do and what we can do better. I think they will work together to be effective leaders for the MOPC.”

Nickell has his own large shoes to fill, those of COO Carl Monroe, who served as MOPC’s staff secretary for 18 years. Claiming he won’t be as smart as Monroe, the self-deprecatory Nickell did admit, “I’ve got good people around me, so we’ll be fine.”

‘All About Process’

Carias became an MOPC member just last year, though she had previously attended the committee’s meetings in her role as director of wind development for NextEra Energy Resources. She has been with NextEra for more than 11 years, following her discharge as a captain from the Air Force.

The leadership nametags. | © *RTO Insider*

Buffington has been a steady presence on MOPC for several years and recently chaired the Z2 Task Force. She joined KCP&L in 2010 after 13 years with the law firm Skadden Arps Slate Meagher & Flom, and she holds a law degree from American University’s College of Law and an MBA from the University of Missouri-Kansas City.

Buffington said she will focus on ensuring stakeholders receive meeting materials on time, a common complaint in annual stakeholder surveys.

“I’m a lawyer. I’m all about process,” she said. “If you’re trying to elevate the conversation at MOPC, people have to get the materials on time. I don’t like getting materials the day of the meeting and the continual updates to the meeting materials.”

That will be the least of the changes for MOPC in 2019. Under Altenbaumer’s leadership, the board has delegated additional authority to the committee, relinquishing its approval of changes to SPP’s Tariff or criteria. Unless there’s a dispute requiring an appeal to the board, MOPC will now have final authority for those changes.

“That’s a huge change,” Carias told stakeholders. “These are exciting times in SPP.”

Nickell said he and Carias plan to adhere to Robert’s Rules of Order, which was evident during Tuesday’s meeting.

“The result of [some] debate won’t go to the board anymore,” he said. “If that puts more emphasis on MOPC resolving those issues at MOPC, we’ll have to get better at following those rules. I think motions need to be clearly understood, and the best way is seeing those in writing on the screen before a vote is taken.”

January 16, 2019

More Info Needed on Tx Line Options, MD PSC Says

By Rich Heidorn Jr.

The Maryland Public Service Commission extended the schedule for its review of Transource Energy’s controversial Independence Energy Connection for 30 days to allow parties to provide additional evidence on proposed alternatives.

The PSC rejected a motion by the Power Plant Research Program (PPRP) of the Maryland Department of Natural Resources to dismiss Transource’s application for a certificate of public convenience and necessity (CPCN) or suspend the schedule.

But the commission’s Jan. 15 ruling set a new deadline of Feb. 25 for the PPRP, PSC staff, the Office of People’s Counsel (OPC) and local residents opposing the line to file direct testimony (Case #9471).

PSC staff and OPC supported PPRP’s argument that the PSC should reject the project because Transource failed to examine alternative solutions as required by state law. Staff recommended the commission grant the motion, suspend the procedural schedule and direct Transource to supplement its application.

The $372 million project would add two 230-kV double-circuit lines, totaling about 42 miles across the Maryland-Pennsylvania border.

Once referred to as the AP South Congestion Improvement Project, Transource’s Independence Energy Connection project would consist of two lines. The western portion would run from the Ringgold substation in Maryland to the Rice substation in Pennsylvania. The eastern line would run from the Conastone station in Maryland to the Furnace Run station in Pennsylvania. | *Transource*

The PPRP said Transource had failed to meet requirements to examine alternatives if an existing transmission line “is convenient to the service area; or the use of the transmission line will best promote economic and efficient service to the public.”

The agency said the need for the eastern segment of the project could be met by the existing Furnace Run-Conastone and Furnace Run-Graceton 230-kV double-circuit transmission tower lines, each of which has only one 230-kV circuit and could carry a second. (See Cancel Transource Line, Md. Panel Says.)

Transource responded it was not required to study PPRP’s proposed alternative and said it met the requirements of state law by analyzing “over 30 study segments.”

“Disputes over whether the commission should consider an alternative are properly the subject of competing testimony at the evidentiary hearing,” Transource said.

The commission said it was modifying the procedural schedule to allow the parties to conduct additional analysis or discovery regarding the use of PPRP’s alternative.

“In response to PPRP’s motion, Transource acknowledges that as the CPCN applicant — the party with the burden of proof — it should be prepared to present evidence at the hearing to address any suggestions by other parties that the proposed project should be denied because there exists a clearly superior alternative,” the commission said. “This criteria includes the existing transmission line evaluation requirements set forth in [section 7-209 of the Public Utilities Article, Maryland Annotated Code].”

Rebuttal testimony will be due by March 18, with surrebuttal testimony and any PPRP response to public comments due April 1. The commission said it will allow live rejoinder testimony if needed during the evidentiary hearings.

Mary Urban, community affairs representative for Transource, issued a statement reiterating it has met all filing requirements under Maryland law.

“Transource has presented a substantial amount of information regarding alternatives,” Urban added. “As the case proceeds, the company will respond as is appropriate under commission rules.”

PJM said in November the project would reduce load costs by $707.3 million in net present value over 15 years, producing a benefit-cost ratio of 1.4. PJM declined to comment Tuesday.

Assistant Attorney General Sondra Simpson McLemore, who filed the motion to dismiss for PPRP, did not immediately respond to a request for comment.

January 15, 2019

PG&E Says It Will File Bankruptcy, as CEO Steps Down

By Hudson Sangree

PG&E Corp. and its subsidiary Pacific Gas and Electric will file for federal bankruptcy protection by Jan. 29, the companies announced Monday, capping a tumultuous week in which PG&E’s stock price plummeted and its credit rating was downgraded to junk status by two major ratings firm.

A day earlier, PG&E said CEO Geisha Williams would be stepping down and leaving the company. Her tenure with the company has coincided with major disasters, including the 2010 San Bruno gas line explosion as a senior executive, and the 2017 wine country fires and 2018 Camp Fire, the deadliest in state history.

Together, those three events killed 104 people, destroyed 28,000 structures and burned approximately 400,000 acres. PG&E was found criminally liable for the San Bruno explosion, which wiped out a suburban San Francisco neighborhood. The Tubbs Fire, which burned down the northern part of Santa Rosa, Calif., in October 2017 and the Camp Fire, which leveled the town of Paradise in November 2018, remain under investigation, though PG&E equipment is a suspected cause of both.

In a U.S. Securities and Exchange Commission filing Monday, PG&E said it faces $30 billion in liability for the last two fire seasons, not including punitive damages, fines or penalties, which could add up to billions more. As of Friday, 750 lawsuits had been filed against PG&E for the Camp Fire and the wine country fires on behalf of a total of 5,600 plaintiffs, the company said. Eleven of the lawsuits are seeking class-action status, it said.

PG&E said its liability insurance and liquid assets would cover only a small fraction of those claims, and that bankruptcy was its only recourse.

“Following a comprehensive review with the assistance of our outside advisers, the PG&E board and management team have determined that initiating a Chapter 11 reorganization for both the utility and PG&E Corp. represents the only viable option to address the company’s responsibilities to its stakeholders,” PG&E Chairman Richard C. Kelly said in a news release.

A recent state law requires the company to give a 15-day advance notice of its intent to file for bankruptcy.

PG&E, founded 114 years ago in San Francisco, announced it was seeking bankruptcy protection this week as it faces $30 billion in liability for deadly wildfires in 2017 and 2018.

Ensuring Operations

PG&E said it expects to continue to be able to provide uninterrupted electric and gas service to its 16 million customers across 70,000 square miles of Northern and Central California. PG&E’s service territory stretches from near the Oregon border in the north to Santa Barbara County in the south, and from the coast to the Sierra Nevada mountains.

The company told the SEC, however, that it does not plan to pay the $21.6 million in interest due Tuesday on its outstanding senior notes, although it had 30 days to make the interest payment before triggering a default.

It said it knows that parties it does business with will worry about getting paid too, but it expects to meet its obligations. (See related story, PG&E Credit Woes Spread, Worrying CAISO Members.)

“PG&E expects that the decision to seek relief under Chapter 11 will raise concerns among its constituencies, including customers, vendors, suppliers and employees, and may lead to a contraction in trade credit and the departure of key employees,” it said. “PG&E has taken steps, however, to mitigate the impact of these potential developments.”

That includes seeking debtor-in-possession (DIP) financing available to companies in bankruptcy.

“PG&E expects to have approximately $5.5 billion of committed DIP financing at the time it files for relief under Chapter 11 on or about Jan. 29, 2019, and has received highly confident letters from a number of major banks,” the company wrote. “The DIP financing will provide PG&E with sufficient liquidity to fund its ongoing operations, including its ability to provide safe service to customers.”

California’s new governor, Gavin Newsom, issued a press release Monday saying he’d been monitoring the situation closely.

“When I took office one week ago today, I immediately instructed my team to meet with the California Public Utilities Commission, CAISO, PG&E and labor unions representing the workers who work for PG&E,” Newsom said. “My staff and I have been in constant contact throughout the week and over the weekend with these stakeholders and regulators. Everyone’s immediate focus is, rightfully, on ensuring Californians have continuous, reliable and safe electric and gas service.

“While PG&E announced its intent to file bankruptcy today, the company should continue to honor promises made to energy suppliers and to our community,” he said. “Throughout the months ahead, I will be working with the legislature and all stakeholders on a solution that ensures consumers have access to safe, affordable and reliable service, fire victims are treated fairly, and California can continue to make progress toward our climate goals.”

‘Very Short Runway’

Some said it isn’t too late for California lawmakers to head off bankruptcy.

ClearView Energy Partners, a research firm based in D.C., said the State Legislature could pass a bill that extends provisions of last year’s Senate Bill 901. That measure allows the CPUC to apply a financial stress test for 2017 wildfire liability to determine how much a utility can afford to pay without harming its customers or destroying its business.

Lawmakers could extend that provision to cover 2018 fires, giving PG&E another route to remain solvent, ClearView said in an email to its clients.

“The 15-day notice offers a very short runway for lawmakers to act before Chapter 11 proceedings could begin,” the firm said. “We have observed lawmakers in California and other states move quickly when faced with an immediate concern. Still, the high degree of controversy and public outcry stemming from wildfire damages and perceived blame assigned to PG&E likely creates headwinds in the legislative process. Each day that passes without a legislative proposal could diminish the prospects for a legislative ‘fix.’”

Even after Jan. 29, it may be possible to stop the bankruptcy proceedings, ClearView said.

“We are not bankruptcy experts, but our state sources indicate that the initial steps in the Chapter 11 process are reversible. In other words, if state lawmakers do enact a law after January to change liability risk from wildfires that occurred last calendar year, PG&E could halt the proceeding. Still, we believe lawmakers need to take some action by the end of the month.”

SB 901 was a compromise measure put together hastily at the end of last year’s legislative session. (See California Wildfire Bill Goes to Governor.) Earlier, then-Gov. Jerry Brown called for lawmakers to overturn state court precedent that holds utilities strictly liable for all wildfire damage caused by their equipment, regardless of negligence. He was worried that PG&E might declare bankruptcy after the 2017 fires, undermining its support of clean energy and Brown’s ambitious goals related to climate change.

He may have had a point. Last week one of the nation’s largest solar arrays, the Topaz Solar Farm in Central California, had its credit rating downgraded to junk status because it had signed a 25-year power purchase agreement with PG&E. S&P Global Ratings said Topaz, owned by Warren Buffett’s Berkshire Hathaway Energy, could be harmed by PG&E’s inability to pay.

On Monday, the Natural Resources Defense Council said PG&E’s bankruptcy could spell bad news for California’s goals, enshrined in last year’s SB 100, of relying on 60% renewable energy by 2030 and achieving zero-carbon status by 2045.

“As NRDC warned months ago, potential adverse consequences include a loss of state oversight and damage to significant clean energy programs critical to reaching California’s climate goals,” including PG&E’s planned investments in electric vehicle infrastructure, NRDC said in a news release. “At risk could be billions of dollars of funding for PG&E’s nation-leading clean energy initiatives, which are designed to help fight the effects of climate change like these tragic wildfires.”

The legislature reconvened Jan. 7. Lawmakers, some of whom have backed away from supporting PG&E, have yet to offer any bills that could help the utility.

January 15, 2019

Shell Energy Seeks to Avoid Liability in GreenHat Trades

By Rich Heidorn Jr.

VALLEY FORGE, Pa. — Shell Energy N.A. came to the Market Implementation Committee on Wednesday to make its case against PJM’s attempts to recover charges from financial transmission rights that the company purchased from failed GreenHat Energy.

After PJM sought more collateral from GreenHat as its losses mounted in April 2017, the company gave the RTO the rights to collect money it said Shell owed it for purchasing some of its FTR portfolio.

PJM was left emptyhanded when Shell said it had already paid GreenHat all it owed. (See Doubling Down – with Other People’s Money.) But the RTO is hoping to recover some of GreenHat’s losses through its indemnification rules on bilateral FTR trades.

Suzanne Daugherty, PJM | © *RTO Insider*

PJM Chief Financial Officer Suzanne Daugherty presented the RTO’s interpretation of its indemnification rules to the MIC, saying PJM’s Tariff requires secondary market buyers of FTRs to indemnify PJM and its members for “charges, not net charges” related to the position.

“That was purposeful, the way the wording was written,” Daugherty said.

She said PJM believes the rule is clear. “Shell also thinks it’s clear but disagrees with our interpretation,” she said.

After Daugherty spoke, Shell’s Matthew Picardi outlined his company’s position, saying the indemnification provision does not apply to its transactions. In a Jan. 2 filing opposing its Oct. 1 motion to withdraw proposed Tariff amendments related to its indemnification rules, Shell said that, “contrary to PJM’s characterization,” the company has never acknowledged it “sold” FTRs to GreenHat or otherwise triggered the Tariff’s guarantee and indemnification provision.

Even if the provision does apply, Picardi said, PJM is misinterpreting it by requiring indemnifying parties to pay more than the defaulting party would have owed — a heads-I-win, tails-you-lose proposition.

Matthew Picardi, Shell Energy | © *RTO Insider*

“PJM believes that netting is not allowed,” Picardi told the MIC. “We disagree with that.”

He presented an example in which the original holder of an FTR would net a profit of $1,859 over one month if it remained owner while a secondary market buyer of the FTR would owe PJM $1,210 because it was denied profits on days when the FTR was in the black.

Shell made the same arguments to FERC in the docket opened by PJM, in which the RTO proposed Tariff changes that would allow indemnifying sellers to assume negatively valued FTR positions on which its indemnified buyer defaulted.

“Such a provision would provide the opportunity for the indemnifying seller to assume ownership of and manage its exposure to the negatively valued FTRs, regardless of the disposition process for the remaining FTR positions in the defaulting member’s FTR portfolio,” PJM said. “At the very least, electing this option would not put the seller in any worse position, since indemnifying sellers are already responsible for the charges associated with those bilateral FTR positions if the indemnified buyer does not pay such costs itself” (ER19-24).

“Such an assumption would allow the indemnifying seller the ability to manage its exposure from its indemnification, but it also protects PJM and its members because the indemnifying seller is assuming the volatility and of course providing the requisite credit,” the RTO added.

Shell Energy presented an example in which the original holder of an FTR would net a profit of $1,859 over one month if it remained the owner while a secondary market buyer of the FTR would owe PJM $1,210 because it was denied payments on days when the FTR was profitable. | *Shell Energy N.A.*

After FERC staff issued a deficiency notice seeking more information on its indemnification procedures, however, the RTO asked to withdraw its filing, saying “the proposal does not provide sufficient benefits to the PJM membership to justify PJM continuing to seek approval.” (See “Bilateral FTR Retraction,” PJM MRC/MC Briefs: Dec. 6, 2018.)

Although it opposed PJM’s proposed Tariff change, Shell asked FERC not to end the docket, saying the withdrawal would prevent the commission from ruling on its dispute with the RTO over the existing indemnification rules.

“Members subject to a guarantee and indemnification claim by PJM should be able to assume all of the FTRs subject to the claim,” Shell said. “Under PJM’s proposed tariff amendment, only negatively valued FTRs subject to the claim could be assumed, which leaves the party with PJM’s improper calculation of guarantee payments for any FTRs not assumed.”

Shell said the commission should only close the docket if it simultaneously opens a Section 206 proceeding to determine whether PJM’s interpretation is correct or unjust and unreasonable. “Allowing PJM to withdraw its Tariff amendment without initiating a Section 206 proceeding will leave members with little choice but to file a complaint for relief,” Shell said.

Separately, the RTO has asked a judge in Harris County, Texas, to compel depositions by GreenHat’s principals as a prelude to a potential civil suit against the traders. GreenHat responded with a counterclaim alleging Shell reneged on $70 million it owes for the transactions (Case No. 2018-69829).

Shell responded that the Texas court lacks jurisdiction over GreenHat’s claim. The court rejected Shell’s argument and created a second docket for the companies’ dispute.

January 15, 2019

Monitor Sees Problems with PJM Reserve Pricing Plan

By Michael Brooks and Rich Heidorn Jr.

VALLEY FORGE, Pa. — PJM’s proposed revisions to how it prices reserves in its energy market necessitates changes in the RTO’s capacity market to prevent substantial overpayment by customers for electricity and the exercise of market power by generators, Independent Market Monitor Joe Bowring said Friday.

Without a true-up, PJM’s package of changes, being developed under a Jan. 31 deadline imposed by the RTO’s Board of Managers, would result in the overpayment of at least $6 billion to generators over four years after its implementation, Bowring told the Energy Price Formation Senior Task Force (EPFSTF), as well as significantly higher overpayment after that without specific market design changes in the capacity market.

“PJM’s apparent goal is to shift revenue from the capacity market to the energy and reserve markets,” Bowring said in a presentation. If so, he said, “there must be a clear and verifiable mechanism to ensure that the shift occurs effectively, equitably and efficiently.”

The RTO has proposed raising the maximum price in the operating reserve demand curve (ORDC), used to set prices for reserve products, from $850 to $2,000. The proposed ORDC would raise both energy and reserve prices significantly. PJM would also use the same ORDC in the day-ahead and real-time markets for reserves, introducing the ability to procure primary reserves in the day-ahead and secondary reserves in the real-time. (See Section 206 Filing on PJM Reserve Pricing Likely.)

Bowring said increased energy market revenues won’t result in lower capacity prices without changes to the variable resource requirement (VRR) demand curve. The curve is based on the net cost of new entry (CONE), which considers all generator revenues from energy and ancillary services markets.

The Monitor proposed setting net CONE as the maximum price on the curve. As a result, Bowring said, capacity prices could be $0 under some circumstances when energy market revenues are high.

“You can’t have it both ways,” Bowring said. “If you shift this high level of revenue from the capacity market to the energy market, you’re effectively eliminating the capacity market.”

The Monitor first raised its concerns at the task force’s previous meeting Jan. 4, but Friday’s meeting marked the first time it made explicit its proposals for why the VRR curve needs to change in response to PJM’s proposal.

Capacity markets serve the same function as scarcity pricing, he said: to provide enough revenue to ensure there is adequate supply to meet demand. “I’m not arguing that we should get rid of the capacity market, but if PJM’s changes to increase energy and reserve prices are implemented, we have to make sure people are not paying twice for the same product.”

Bowring said PJM’s logic for the package of revisions “escapes me.” But, he said, if that was what the RTO wanted to do, his concerns would need to be addressed to prevent overpayments.

“I am not sure why PJM believes that there is urgency to this,” Bowring said in an email. “It is not a simple matter, and PJM’s approach has not been adopted by other RTO/ISOs.”

Bowring also said an increased reliance on the energy market will reduce PJM’s ability to “pick the reserve margin quite so precisely.”

“It’s the same lesson ERCOT learned,” he said of the Texas grid operator, which does not have a capacity market.

‘Radical Change’

Adam Keech, PJM executive director of market operations, did not directly dispute Bowring’s arguments. But he did take exception to the idea that the RTO was trying to eliminate the capacity market. “The goal [of PJM’s proposal] is not to shift revenue,” he said at the meeting. “The goal is to price energy and reserves correctly.”

Keech told RTO Insider after the meeting that PJM was waiting for information from the Monitor, “because we have thought about it and not been able to identify what the issues are that they see.”

Bowring said that PJM has explicitly ignored the potential revenue impact on the capacity market during the transition period. “In other words, PJM is proposing that customers pay twice for the same product during the transition period.”

The RTO proposes to use simulations to estimate the increase in energy revenue in defining the VRR curve in the capacity market auctions after the transition period. “PJM clearly has thought about the issues,” he said, “but they have a very different proposal than the IMM’s proposal.”

RTO VRR curve comparison | *Monitoring Analytics*

Stakeholder reaction to Bowring’s presentation was mixed. Brock Ondayko of American Electric Power said that, without further modifications to the VRR curve, he expected capacity to clear at lower prices under the proposed rules because of the increased energy and reserve revenues. Bowring’s predictions “just seem counterintuitive,” he said.

But consultants James Wilson and Roy Shanker, and Susan Bruce, attorney for the PJM Industrial Customers Coalition, agreed the IMM had identified a problem that needed to be addressed.

With the PJM board’s deadline looming, however, it may not matter.

“We’re in an interesting spot, both from a timing and scope perspective,” said Dave Anders, PJM director of stakeholder affairs and chair of the task force, explaining that the capacity market curve is out of scope under the issue charge the Markets and Reliability Committee approved. The MRC’s next meeting is Jan. 24, when the committee is expected to vote on PJM’s proposal.

Anders said stakeholders offering alternatives to PJM’s proposals should include any measures to address the capacity curve issue as an addendum, not as part of the packages to be voted on by task force members Jan. 17. “I don’t want to use the process to ignore what may be a significant issue,” he said.

Bowring said PJM would be foolish to ignore the impact of such a “radical change” to the energy market on the capacity market. “It is going to be part of the scope in front of FERC,” he said.

Transparency Proposal

Wilson, a consultant to consumer advocates in New Jersey, Pennsylvania, Maryland, Delaware and D.C., ended the session with a brief presentation in which he said PJM should make public appeals for conservation when administrative shortage prices reach a threshold so that customers know they are facing high prices and have an opportunity to reduce their consumption. He said the trigger could be the shortage price component hitting $300/MWh.

“It shouldn’t be just a quiet little press release on the PJM website,” Wilson said. “It ought to be on the nightly news.”

PJM’s current rules call for such appeals only when reliability is at risk.

January 15, 2019

PG&E Credit Woes Spread, Worrying CAISO Members

By Hudson Sangree

Concern about the ripple effects of Pacific Gas and Electric’s financial meltdown had already spread last week as CAISO addressed worries about the utility’s potential to default on its payments to the ISO, and a solar farm owned by Warren Buffett’s Berkshire Hathaway saw its credit rating cut to junk status because of its dependence on PG&E.

Those worries will grow after PG&E announced Monday it would file for Chapter 11 bankruptcy protection by Jan. 29 because it faces $30 billion in liability for the catastrophic wildfires of 2017 and 2018. (See related story, PG&E Says It Will File Bankruptcy, as CEO Steps Down.)

On Friday, CAISO issued a market notice aimed at easing concerns about how PG&E’s problems could affect the ISO and its participants.

“The California ISO has received inquiries relating to the financial status of Pacific Gas & Electric Co. in light of recent media reports,” the notice said. “The ISO wants to assure market participants that PG&E has posted collateral with the ISO to cover its outstanding and upcoming obligations.”

Should PG&E default, however, the ISO’s other members would have to pick up the tab. CAISO rules require each market participant to cover default losses “in proportion to the benefits it receives from its activity” in the market. When GreenHat Energy spectacularly defaulted in June in PJM’s financial transmission rights market, other members were angry that they had to cover tens of millions of dollars in payments. (See Greenhat FTR Default a ‘Pig’s Ear’ for PJM Members.)

GreenHat was a relatively small player in PJM, whereas PG&E, California’s largest utility, is a huge part of CAISO. The total volume of energy delivered in CAISO in 2017 was 228,191 GWh, according to the ISO’s annual Market Issues and Performance Report. PG&E’s total deliveries that year were 82,226 GWh, the utility said in its Annual Report to Shareholders.

Bankruptcy Imminent

The question of PG&E’s default isn’t academic. The company’s circumstances have been quickly worsening, raising questions about its ability to continue making ISO payments.

Hours before Monday’s bankruptcy announcement, PG&E said CEO Geisha Williams was stepping down amid the growing turmoil.

Both Moody’s Investors Service and S&P Global Ratings cut PG&E’s credit rating to “junk status” last week, citing the utility’s financial exposure for two years of massive, deadly wildfires along with the waning will of politicians to bail out the state’s largest utility. (See PG&E Stock Plunges, Credit Downgraded to ‘Junk’ Status.)

PG&E’s stock price plummeted after November’s Camp Fire and continued plunging this week amid talk of the company declaring bankruptcy and selling off its gas division. | *Google*

“The downgrade reflected our assessment of a weakening of the company’s governance, the souring political environment that we expect will lead to a weakening of the regulatory construct, what we see as the company’s limited capital market access, and the possibility of a voluntary bankruptcy filing given the immense pressures and uncertainties still facing the company,” S&P said in an update posted on its website Friday.

As of Monday afternoon, PG&E had lost about $32 billion, or nearly 78% of its market value, over 15 months starting in October 2017, when 21 major fires swept Northern California’s famed wine country. Those fires killed 44 people and destroyed thousands of homes, including a substantial part of the city of Santa Rosa.

State fire investigators blamed PG&E for at least 17 of those blazes, and its stock price sunk from more than $70/share to about $38/share. For months, the utility’s stock price hovered in the range of $40 to $50/share, then the Camp Fire struck Nov. 8. The deadliest fire in state history killed 86 people and wiped out the town of Paradise in the Sierra Nevada foothills of Butte County.

PG&E’s equipment quickly fell under suspicion after the company reported to the Public Utilities Commission that it had experienced a problem with a transmission line, and that employees saw flames near the Camp Fire’s point of origin on the morning it started.

The company saw its stock price drop to less than $18/share last week as S&P downgraded its credit rating from investment grade to junk status.

News reports, quoting unnamed sources, suggested the utility might be getting ready to file for bankruptcy — or to put its downtown San Francisco headquarters on the market or sell off its gas division.

By Monday afternoon, PG&E shares were selling for about $8 on the New York Stock Exchange.

‘Negative Implications’

The uneasiness about PG&E’s future has started to spread to companies with which it does business

On Friday, S&P slashed the credit rating of the 550-MW Topaz Solar Farms in San Luis Obispo County to junk, citing its reliance on PG&E, with which it has a 25-year sales contract. Topaz is owned by BHE Renewables, a subsidiary of Buffet’s Berkshire Hathaway Energy. The solar farm was completed at a cost of $2.4 billion in 2015.

The 550-MW Topaz Solar Farms in central California, one of the largest photovoltaic power plants in the world, has been caught up in PG&E’s financial meltdown. | *NASA Earth Observatory*

“Topaz Solar Farms receives all of its revenue from PG&E under a long-term power purchase and sale agreement,” S&P said. “Our rating on the solar project is currently capped by our view of the credit quality of PG&E, its utility offtaker.”

S&P put Topaz on its credit watchlist with “negative implications.”

“The CreditWatch negative listing reflects the increasing risk that we will downgrade PG&E by one or more notches over the next few months. If we lower our ratings on PG&E again, it could lead us to take an equivalent action on our ratings on Topaz Solar Farms.

“If PG&E files for Chapter 11, this could, subject to it being a material adverse effect, trigger a cross default under Topaz Solar’s financing documents unless the power contract is replaced within 90 days of the bankruptcy event,” S&P added.

In a separate post on its website Friday, S&P explained why it had downgraded PG&E’s credit rating from BBB- to B Jan. 7.

“A number of events, over several weeks, contributed to our … multinotch downgrade,” it said.

Immediately after the Camp Fire, it appeared that state lawmakers and regulators would try to keep PG&E afloat to protect ratepayers and to achieve the state’s ambitious renewable portfolio standards, S&P said. A new law, SB 100, requires the state to obtain 60% of its energy from renewable sources by 2030.

But public anger intensified, with protests at PUC hearings and PG&E headquarters. That anger has undermined the will of state regulators and politicians to protect PG&E, S&P said.

An allegation by the PUC in December that PG&E had falsified natural gas safety records made things worse. Politicians who had supported the utility expressed distrust.

On Jan. 4, PG&E issued a press release saying it was planning to shuffle its board of directors and reviewing “structural options,” including in its operations, finances and management. Speculation quickly followed that PG&E might file for bankruptcy.

“It was the totality of these events that led to S&P Global Ratings’ downgrade of PG&E into speculative grade,” the credit rating firm said.

January 15, 2019

PJM PC/TEAC Briefs: Jan. 10, 2019

By Rich Heidorn Jr.

PJM Ponders Rules for Offshore Wind Transmission

VALLEY FORGE, Pa. — PJM is considering changing interconnection rules to accommodate transmission serving offshore wind generation.

Current rules allow merchant transmission developers to obtain transmission injection and withdrawal rights for DC facilities or controllable AC facilities connected to a control area outside the RTO.

PJM’s Sue Glatz presented the Planning Committee a problem statement to consider allowing merchant transmission developers to request capacity interconnection rights, or equivalents, for non-controllable AC transmission facilities.

Glatz said transmission developers have expressed interest in building AC transmission to accommodate future generation interconnection requests. The developers want to acquire capacity interconnection rights so PJM can identify the necessary network upgrades, she said.

The key difference is that the developers want to build transmission before the generation is sited. Without generation at the other end of the line, PJM cannot perform stability or short-circuit analyses, Glatz said.

PJM hopes to develop a FERC filing on Phase 1 of the initiative — focusing on rules for a single offshore generator lead line — by July.

Phase 2 will consider networked offshore transmission for connecting multiple wind sites. A FERC filing is targeted for September 2020. “We view this as much further down the road,” Glatz said.

Theodore Paradise, Anbaric | © *RTO Insider*

John Brodbeck of EDP Renewables N.A. asked PJM to offer education on what open-access rights generators will have to the lines.

Theodore Paradise, ISO-NE’s former assistant general counsel for operations and planning, who has joined transmission developer Anbaric as special counsel, asked for a discussion on how HVDC facilities are modeled in PJM.

The committee will be asked to approve the problem statement at its next meeting.

PJM Seeks Fix on Queue Filing Errors

PJM is proposing a one-sentence rule change to help developers avoid being removed from interconnection queues because of minor errors or omissions.

Interconnection customers are generally granted up to 10 business days to resolve deficiencies found by the RTO. But under changes initiated in 2016, requesters must clear all deficiencies by the last day.

The changes were intended to dissuade developers from late submissions. But PJM said requests are not being submitted any earlier and the changes were undermined by FERC rulings reinstating applicants removed for minor errors.

PJM’s Susan McGill presented the PC a proposed problem statement to ensure that all applicants have up to 10 business days to correct deficiencies, whether they enter on Day 1 or the last day of the six-month queue.

“We can’t have another queue where people get bumped out … they go to FERC and get waivers [to return]. It’s very disruptive,” Vice President of Planning Steve Herling said.

Since the AA1 queue opened in May 2014, 50 to 60% of interconnection requests were submitted in the last month of the queue.

Prior to the 2016 changes, which resulted from the Earlier Queue Submission Task Force, about 18% of projects submitted in the last month of the queue were withdrawn for deficiencies. After the EQSTF changes, that withdrawal rate increased to 24%.

PJM is proposing to give all projects 10 days to address problems by removing the following sentence from the Tariff: “Any queue position for which an interconnection customer has not cleared the deficiencies before the close of the relevant new services queue shall be deemed to be terminated and withdrawn, even if the deficiency response period for such queue position does not expire until after the close of the relevant new services queue.”

“We’re not looking for reasons to get rid of you,” McGill explained.

PJM’s Dave Anders said Manual 34 allows the first discussion of a problem statement to include a proposed solution if the committee chair determines “the problem presented is sufficiently simple.”

Herling said, “We do have more changes we think need to be made [to interconnection queue rules]. But that will require a more robust conversation.”

PJM Pondering Wind Capacity Measures

Wind generators could see lower capacity credits under rule changes being considered by the RTO.

PJM’s Tom Falin presented the PC with the updated results of the RTO’s analysis of wind and solar resources’ effective load carrying capability (ELCC) — a measure of the additional load that a group of generators can supply without a reduction in reliability.

Effective load carrying capability is a measure of the additional load that a group of generators can supply without a reduction in reliability. | *PJM Renewable Integration Study (2014), General Electric*

The new results use the 2018 reserve requirement study (RRS) capacity model, which shows nameplate capacities for 2022/23 of 14,620 MW of wind and 5,290 MW of solar.

PJM found the average wind ELCC between delivery year 2009/10 and 2017/18 was 11.5%. That suggests the RTO’s current practice of using wind’s average capacity factor of 17.1% overstates wind’s value, Falin said. The median capacity factor over that period was 8%.

“We feel [the median is] a much, much better indicator of the reliability value” of the resources than the average, Falin said.

PJM found the average solar ELCC since 2012/13 is 42.3%, close to the average capacity factor of 42.1% and median capacity factor of 40.9%.

Falin posed two questions to stakeholders: Should PJM continue with its original proposal to change the intermittent resource capacity credit calculation from an average value to a median value? Or should it base the calculation on the ELCC methodology?

He said the advantage of changing from average to median capacity factor is “it’s much less of a black box” than ELCC.

Although the figures represent ELCC values RTO-wide, PJM said the ELCC must be allocated to individual generating units based on individual unit performance.

PJM calculates capacity credits for existing wind resources by multiplying the ELCC by the total nameplate. The RTO has three options for prorating the total capacity credit for existing units:

The average output of an individual unit during a specified number of daily peak hours in each year for which the unit was in-service;
The average output of an individual unit during the daily peak hours in which the loss-of-load expectation (LOLE) is non-zero in each year for which the unit was in-service; or
The average output of an individual unit during hours ending 3, 4, 5 and 6 p.m. during the summer season in each year for which the unit was in service.

Falin said the second option could involve as few as three hours or as many as 12 per year. The last option — PJM’s current method — has the advantage of being based on a lot of data, making it more stable than the other choices. But Falin said it also includes many hours with no LOLE risk.

For new resources, the credit can be calculated by:

multiplying the systemwide ELCC by the nameplate of the new unit (as MISO does);
multiplying an estimated zonal ELCC by the nameplate of the new unit; or
multiplying an estimated unit-type ELCC by the nameplate of the new unit.

RTO-wide ELCC values will be updated each year as part of the installed reserve margin study.

New units will continue to have the option to provide data justifying capacity credits greater than the ELCC value. As under current rules, new units’ actual performance will be rolled in over a three-year period.

PJM wants to develop manual language and request MRC endorsement by the April meeting so that unforced capacity (UCAP) values for wind and solar can be posted by May 1 for use in the 2022/23 Base Residual Auction in August.

The changes would be effective June 1, 2022; thus, they would not affect UCAP values from prior auctions.

Transmission Expansion Advisory Committee

Dominion Plans $7.5M Substation Project

Dominion Energy plans to spend $7.5 million on a new substation to accommodate a new data center campus in Fauquier County, Va., with a total load of more than 100 MW.

The company will interconnect a new Lucky Hill substation between the Remington and Gordonsville substations on line #2199, a 230-kV circuit.

The requested in-service date is Sept. 15, 2020.

Supplemental Projects More than Double Baseline Additions in 2018

Transmission owners proposed $5.7 billion in supplemental projects in 2018, more than double the $2.065 billion in baseline projects included in the 2018 Regional Transmission Expansion Plan, PJM’s Aaron Berner told Transmission Expansion Advisory Committee members Thursday.

Most of the supplemental projects were presented by American Electric Power ($2.4 billion) and Public Service Electric and Gas ($1.46 billion).

More than half of the baseline projects were attributed to aging infrastructure.

Transmission owners’ supplemental projects have outpaced baseline projects in all but one year since 2015, totaling almost $15 billion. Baseline projects totaled only $8.1 billion over the same period. | *PJM*

Reliability Window Likely in June

In an update on the assumptions for the 2019 RTEP, Berner said the RTO expects to open a reliability window for proposals in June.

The 2010 RTEP will include 27 locational deliverability areas and Ohio Valley Electric Corp. FERC approved OVEC’s integration into PJM last February.

Generation with executed facilities study agreements (FSAs) will be modeled offline along with associated network upgrades, which will be analyzed separately. Berner said PJM could “turn on” FSA generation and their upgrades if there are many generation retirements but said the RTO does not expect to do so.

Travis Stewart of Gabel Associates said the American Wind Energy Association would like PJM to analyze the consumer benefits of states sharing the costs of transmission to accommodate their renewable portfolio standards. Stewart said AWEA wants more information on projects that could relieve congestion and allow PJM to access higher quality wind in the Midwest. The group may request PJM consider an RPS build-out as an RTEP future, he said.

PJM to Sunset Regional Planning Process Task Force

PJM notified stakeholders Friday that it plans to sunset the Regional Planning Process Task Force on Feb. 1 unless it receives objections from stakeholders within the task force, PC or the Markets and Reliability Committee.

The MRC voted in April 2015 to place the task force on hiatus in case it needed to be reconvened to address FERC Order 1000 or other issues. (See “Regional Planning Process Senior Task Force Placed on Hiatus,” PJM Markets and Reliability Committee & Members Committee Briefs.)

Any comments should be sent to Susan.Snyder@PJM.com.

January 15, 2019

PJM Market Implementation Committee Briefs: Jan. 9, 2019

By Rich Heidorn Jr.

VALLEY FORGE, Pa. — It was one of the shortest Market Implementation Committee meetings in memory Wednesday as stakeholders clocked out in only two and a half hours following discussions of the must-offer exception process, FERC’s energy storage order and PJM’s indemnification rules on bilateral trades of financial transmission rights. (See related story, Shell Energy Seeks to Avoid Liability in GreenHat Trades.)

PJM May Split Rule Changes on Must-offer Exceptions

PJM may seek approval of widely supported changes to the must-offer exception process while having further discussions on revisions that lack consensus, RTO officials told the MIC.

The MIC approved a package of rule changes proposed by PJM MRC Briefs: Dec. 20, 2018.)

The process behind the rule changes was initiated by Exelon to investigate issues including the process for existing capacity resources with a must-offer requirement to become energy-only resources.

The changes with widest support would allow market participants to voluntarily remove a generator from its capacity resource status by making a request to PJM and the Independent Market Monitor. It would also permit participants to request exemptions from multiple auctions in a single exception request. It would allow such changes for new resources that cannot be completed by the start of the delivery year for which it cleared.

There is less consensus on a rule that would require generators to forfeit their capacity injection rights (CIRs) if they are repeatedly approved for CP must-offer exceptions and not offered in capacity auctions for three consecutive delivery years.

Monitor Joe Bowring said the proposed changes failed to strike the right balance.

Bowring said PJM should discourage generators from holding on to CIRs for a long period of time because “they can’t make up their mind” about being a capacity resource.

“If someone has a clear plan, and they’re following it, that’s fine,” Bowring said. “We think this [proposal] allows more than that.”

Carl Johnson, representing the PJM Public Power Coalition, was also critical. “I’m struggling to find anything I like about any of this,” he said. “This doesn’t hang together to me as an effective set of rules.”

Sharon Midgley of Exelon asked PJM to move forward on the parts of the package with wide support, saying the only issue in dispute was over the RTO involuntarily seizing CIRs from generators after three years of successive must-offer exception requests.

PJM stakeholders are still debating a rule change that would require capacity resources to become energy-only after three consecutive years of exemptions from must-offer rules. | *PJM*

But Marji Philips of Direct Energy said her company would not support a “quick fix” based on what has been proposed to date. “The process as proposed is a little bit loose yet,” she said, adding that CIRs are “a very serious barrier to new entry.”

A few stakeholders rekindled an earlier debate over whether CIRs are generators’ “property rights.”

Gary Greiner of Public Service Enterprise Group said stakeholders need PJM’s opinion on the issue. “We’ve kind of danced on the periphery, but we’ve never come at it head on,” he said.

PJM’s Pat Bruno said the RTO may split the issue so it can seek approval of its non-controversial elements. He said the RTO will conduct additional discussions with stakeholders before the next MIC.

Electric Storage Rules Require Manual Changes

PJM’s Laura Walter gave stakeholders an update on the RTO’s implementation of rules opening its markets to e lectric s torage, saying as many as 15 manuals may require revisions.

PJM made two filings to comply with FERC Order 841 on Dec. 3, one covering markets and operations (ER19-469) for which comments are due Feb. 7, and a second governing accounting (ER19-462), for which the comment period closed on Jan. 4. The RTO plans to implement the changes by Dec. 3.

Walter said stakeholders will be asked for feedback on energy storage cost offers at the February MIC meeting. Among the items to be discussed will be whether cost offers should be based on inventory cost (historical weighted average cost of stored energy available for discharge, adjusted for round-trip efficiency); opportunity costs (expected lost net revenue from operating in a given hour); or replacement cost (estimated future weighted average cost of charging energy over the next available operating period).

First drafts of manual revisions will be presented before July, Walter said.