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November 12, 2024

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FERC Orders PJM to Unwind GreenHat Settlements

By Rich Heidorn Jr.

PJM must unwind five months of settlements for GreenHat Energy financial transmission rights that should have been liquidated sooner, FERC ruled Wednesday (ER18-2068).

In addition to rejecting PJM’s request for a waiver of its liquidation rules, the commission also rebuffed the RTO’s request to retain $550,000 in collateral posted by one of GreenHat’s principals through a second company (ER18-1972).

The two rulings complicate the RTO’s efforts to minimize the damage of GreenHat’s default, which left other PJM members liable for more than $100 million.

The commission also disclosed that its Office of Enforcement is conducting a nonpublic investigation into whether GreenHat engaged in market manipulation or violated other commission rules. “That investigation is ongoing. The commission will determine what further action, if any, may be appropriate after it considers the results of the staff investigation,” FERC said.

The RTO said it will ask the commission to reconsider its ruling on the liquidation waivers.

“PJM took the appropriate and immediate steps in the public interest, based on the legal vehicles and FERC precedents in effect, to stop a liquidation in an auction that was dysfunctional,” RTO spokesman Jeff Shields responded late Wednesday. “PJM is disappointed that FERC, in its order, may not have fully appreciated the magnitude of the impact to our members and to consumers. PJM intends to file a rehearing and/or clarification request, and a motion to stay the order. We will have a notification for members in the coming days.”

PJM analysis shows the continuing downward trajectory of GreenHat’s FTR portfolio. | PJM

On Nov. 29, the commission had approved Tariff and Operating Agreement revisions that require defaulted FTR portfolios to go to settlement rather than being liquidated through auction (ER19-19). (See FERC OKs Key PJM Changes to Address GreenHat Default.)

But the commission on Wednesday declined to make those rule changes retroactive, saying the waivers could harm other FTR market participants who had relied on the RTO’s existing rules.

As described by FERC, PJM “paused aspects of” the July FTR auction after all bids and offers had been received, saying it was alarmed by a lack of liquidity and the size of risk premiums related to the GreenHat FTRs.

PJM said it would instead sell off the positions during the long-term FTR auction in September and the monthly auctions between July and October, offering only those positions effective in the prompt month (i.e., selling August FTR positions at the July auction, September FTR positions in the August auction, etc.)

The RTO asked FERC on July 26 for a waiver of Tariff rules requiring it to offer all of GreenHat’s FTR positions at a price designed “to maximize the likelihood of liquidation,” saying a slower liquidation of the company’s large portfolio would reduce losses to members.

FERC ruled that the request was not limited in scope.

“Changing the rules governing an already-commenced auction is a significant step that affects both the outcome of that particular auction as well as parties’ confidence in the rules governing future proceedings. That is particularly so here, where the record indicates that PJM proposed the waiver in order to avoid the outcome that the already-commenced auction would have produced,” FERC said.

“In addition, we note that PJM proposes to waive four discrete elements of the Tariff in order to potentially substitute new rules that were not yet formed, much less included in the record, at the time PJM made its waiver request. Such a significant change to multiple parameters of an already-commenced auction is not a remedy that is limited in scope. The record demonstrates that participants submitted bids in the July monthly FTR auction relying on the liquidation process that existed at the time PJM conducted the auction. Disrupting those settled expectations is likely to cause harm to third parties, even if doing so might produce [an] otherwise more efficient outcome, as PJM contends the waiver request would.

“To the extent PJM anticipated that the commission would grant the waiver request … PJM is required to reconcile any such actions by reinstating the original July auction results, or taking steps that are necessary to comply with the effective Tariff language when the July 2018 auction was conducted, and by unwinding settlements made for September, October, November, December and January positions that should have been liquidated.”

‘Unreasonably Harmed’

Separately, the commission also rejected PJM’s request to withhold $550,000 in collateral posted by Orange Avenue, a second company owned by one of the GreenHat principals.

PJM asked to retain the collateral for up to one year while it decides whether to take legal action against GreenHat and apply Orange’s collateral to GreenHat’s debts.

Orange posted the collateral in February 2018, but before doing any trading, it sought on June 4 to withdraw from PJM and recover the collateral.

When 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 Energy owed it for purchasing some of its FTR portfolio. PJM was left emptyhanded, however, when Shell said it had already paid GreenHat all it owed. (See Shell Energy Seeks to Avoid Liability in GreenHat Trades.)

PJM said it is reviewing whether to take legal action against GreenHat over its representations in negotiating the pledge agreement.

FERC denied PJM’s request to hold Orange’s money in the interim, saying the company “would be unreasonably harmed.”

“While PJM states that it intends to investigate potential fraud with respect to the execution of the pledge agreement by the managing member of GreenHat, PJM fails to make any claim that Orange may have participated in any fraud, pointing out only that GreenHat and Orange have the same managing director. On the evidence submitted by PJM, therefore, we find that Orange would be unreasonably harmed by granting PJM a waiver request.”

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FERC Clarifies ISO-NE Generator Delist Bid Rights

By Michael Kuser

FERC on Tuesday clarified on remand that a capacity supplier’s retirement bid can enter ISO-NE’s Forward Capacity Auction if the supplier demonstrates that the bid is just and reasonable, despite contrary assertions by the RTO’s Internal Market Monitor (ER16-551-004).

The D.C. Circuit Court of Appeals on Dec. 28 remanded back to the commission its original October 2017 order accepting ISO-NE’s retirement delist bid mechanism in the FCA (Exelon v. FERC, 17-1275). The court’s action was based on the commission’s own explanation at oral argument that a market participant — and not ISO-NE or the Monitor — has the right to show that its filed rate is just and reasonable and will be entered into an auction regardless of the Monitor’s proposed offer price (ER16-551-003). FERC had until Feb. 1 to respond.

“We see no way to skirt the question Exelon tees up: Under ISO-NE’s new Tariff rules, does a supplier’s rate enter the auction so long as it convinces the commission that the rate is just and reasonable, over contrary claims of the Market Monitor?” the court said.

Brayton Point Power Plant

Ambiguous Language

FERC found that “certain aspects of the relevant Tariff language and the commission’s prior orders interpreting that language are ambiguous.” It ruled that the RTO’s filing must include “the relevant information and justification submitted by both the capacity supplier and the Internal Market Monitor.”

The commission last March approved ISO-NE’s request to reduce the dynamic delist threshold for FCA 13 to $4.30/kW-month from the $5.50/kW-month used in FCAs 10 to 12 (ER18-620). The threshold, which must be revised every three years, is a key parameter for generators considering retirement, which must submit delist bids to opt out of the capacity auction. (See FERC OKs Lower Delist Threshold in ISO-NE.)

“To the extent that the commission’s prior orders in this proceeding can be interpreted as inconsistent with our answers to the court’s remand, we reject those interpretations,” FERC said in the Jan. 29 order, which revised paragraphs 18, 19 and 25 of the Oct. 30 order.

“As the court correctly noted, in the case of a conditional retirement, a mitigated bid is entered into the auction, but the resource will only retire at its originally submitted price,” the commission said. “If the clearing price is below both the original bid and mitigated bid, the unit retires. If the clearing price is at or above both bids, the supplier takes on a capacity obligation. If the clearing price is at or above the mitigated bid but below the original bid, the unit must retire.”

Accepts CASPR Tariff Revisions

In a separate order Tuesday, the commission accepted the RTO’s Tariff revisions to support implementation of the Competitive Auctions with Sponsored Policy Resources (CASPR) rules that the commission accepted in March 2018 (ER19-444). (See Split FERC Approves ISO-NE CASPR Plan.)

“With respect to the test price mechanism, we find that it is a just and reasonable means to address the potential incentive for bid-shading created by the CASPR modifications to the Forward Capacity Market,” the commission said. “Bid-shading” refers to the practice of resources electing to offer their capacity below the RTO’s assessment of their going-forward costs.

ISO-NE filed the Tariff revisions Nov. 30 after FERC on July 2 denied a Tariff waiver to allow the RTO to enter a cost-of-service agreement to keep Exelon’s 2,274-MW Mystic plant running after its capacity supply obligations (CSOs) expire in May 2022. The commission instead directed the RTO to revise its rules to allow such agreements in order to address fuel security. (See FERC Denies ISO-NE Mystic Waiver, Orders Tariff Changes.)

‘Confounding Interpretation’

In a partial dissent, Commissioner Richard Glick said the RTO seemed to be working at cross-purposes to the stated mission of CASPR’s substitution auction to provide state-sponsored resources subject to a minimum offer price rule (MOPR) a chance to purchase a CSO — and the associated revenue stream — from a resource that then retires from the market.

“ISO-NE adopted what can only be described as a confounding interpretation of what qualifies as a state-sponsored resource,” Glick said, referring to a provision requiring the resource be located within a state’s geographical boundaries.

“Specifically, the [RTO] concluded that an offshore wind facility that is procured pursuant to a state-mandated solicitation and that is electrically located in that state does not qualify as a state-sponsored resource for the purpose of the renewable technology resource exemption (RTR) to the MOPR, which CASPR retained as a transition mechanism to the fully fledged substitution auction,” he said.

Glick characterized the RTO’s interpretation as “discouraging” and as putting up “an unnecessary barrier to the type of resources that CASPR was supposed to accommodate.”

The RTO also proposed to bar from the substitution auction resources that bid-shade even if those resources clear the capacity construct and receive a CSO. Glick said the “unambiguous result” of that change “will be to again tilt the scales in favor of retaining traditional resources and against the incorporation of state-sponsored resources. As a result of this proposal, a resource that might otherwise retire through the substitution auction will instead remain in the market, holding a CSO that it could have sold to a state-sponsored resource.”

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Cold Snap Halts DER Talk as MISO Calls Max Gen Event

By Amanda Durish Cook

CARMEL, Ind. — A dangerous cold snap spurred a maximum generation event and knocked out power to MISO’s offices Wednesday.

The arrival of the polar vortex cut short a two-day RTO workshop focusing on distributed energy resource participation, canceling an in-depth discussion on the technical concerns of adding significant amount of DERs to the grid.

As MISO security checked identification with flashlights in a darkened lobby about 8 a.m. and sent staff to work from home, temperatures hit -10 degrees Fahrenheit with a -40 windchill. At the same time, Minneapolis registered -30 F and a wind chill below -50.

By then, the MISO Reliability Coordinator had declared conservative operations, suspending all transmission and generation maintenance, and a maximum generation event for its North and Central regions because of forced outages and higher-than-expected load. Both declarations will last through Thursday. The power outage did not extend to the control room. MISO first issued a cold weather alert on Jan. 25 covering Jan. 29 to Feb. 1. (See MISO Issues Cold Weather Alert.)

An empty Indianapolis street on Jan. 30 | © RTO Insider

The first day of the workshop on Jan. 29 focused only on an introduction to DERs, with speaker Bob Shively of Enerdynamics outlining the several unknowns surrounding DER adoption. The second day was to focus on topics such as DER interconnection, forecasting and reliability issues.

After relative quiet in public stakeholder groups on DER penetration for several months, MISO leadership last year said it will begin work on a possible participation model in anticipation of a FERC rule on the issue. (See MISO Offers Storage Proposal, Promises to Exceed Order 841.) Before the inclement weather, the RTO had already planned two more two-day DER workshops in March in cooperation with the Organization of MISO States.

Staff said that although NERC has a definition of DERs, MISO has yet to establish its own independent definition.

The Unknown

Shively said there’s a great deal of uncertainty about how quickly DERs will permeate the energy landscape.

“It could happen in some states very quickly. It could happen in other states not so quickly. … We don’t know what’s going to be the adoption curve of consumers. … You can get people saying this, and people saying that. The answer is nobody really knows. You need to do your planning in mind thinking that nobody really knows,” Shively said.

He then cited Bill Gates’ book “The Road Ahead”: “We always overestimate the change that will occur in the next two years and underestimate the change that will occur in the next 10. Don’t let yourself be lulled into inaction.”

But Shively said planners will have to anticipate what they literally cannot see today.

The bulk electric system and markets are not designed to incorporate DERs, he said, which lack visibility on the grid, leaving planners to exclude them in their models when they do not receive operational data.

“Bulk power system planners do not have access to data on distributed energy resources. … All that data rests with distribution companies and there’s really no coordination,” Shively said.

Several factors will affect the rate of DER adoption, he said, including the pace of state regulation and a possible FERC ruling. In some cases, he’s already witnessed the need to equip substations at the distribution level to allow generation from DERs to flow back to the grid. However, he noted, early compensation, new reliability rules and net metering changes can make or break widespread adoption. Different states might experience wildly different penetration rates. He also said utility distribution companies may have to create special DER monitoring systems.

Shively said distribution companies will soon need to reinvent themselves as DER communications networks.

“I had a guy from Duke tell me, ‘We’re no longer an energy company. We’re a high-tech communications data energy grid,’” Shively said.

He also pointed to New York’s Reforming the Energy Vision, a set of multiyear regulatory decisions and policy initiatives launched in 2014 with the goal of creating a distributed system platform provider, among other objectives.

“It’s probably harder to plan DER integration on distribution versus transmission. For distribution, you’re changing the whole way you model each of your distribution circuits,” Shively said.

‘Sneaky’ Devices

Shively said all internet-enabled devices today have the potential to become a DER.

“Anyone who has Alexa or Google to control the lights, you have a potential distributed energy resource in your home,” he said.

Shively cited a recent Wall Street Journal article on Google and Amazon planning for industry traction in third-party home automation and home area networks.

“More and more, things you’re buying today are sneakily internet-enabled whether you want them to be or not,” Shively said. He said soon, customers may be able to dictate rules such as adjusting the thermostat by 2 degrees when kilowatt-hours reach a certain price.

MISO’s next DER workshop will be held March 21-22 in Metairie, La.

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PG&E Wants to Undo Contracts, Revamp Biz in Bankruptcy

By Robert Mullin and Hudson Sangree

PG&E Corp. and its subsidiary Pacific Gas and Electric Co. confirmed in court papers Tuesday the companies hope to rescind costly power purchase agreements and reform their obsolescent business model during a bankruptcy process that kicked off with a midnight filing for Chapter 11 reorganization. (See PG&E Files for Bankruptcy.)

In doing so, the utility giant challenged two recent rulings by FERC in which the commission said it shares authority with a bankruptcy judge in San Francisco to decide if wholesale power purchase agreements can be repealed or modified in the course of bankruptcy. (See FERC Claims Authority Over PG&E Contracts in Bankruptcy.) The first hearing before that judge Tuesday gave some insight into how contentious the issue could become.

Philip Burton Federal Building, San Francisco | U.S. Bankruptcy Court – Northern District of California

PG&E said Tuesday it has 387 power purchase agreements with 350 companies worth about $42 billion. Those PPAs represent 13,668 MW of contracted capacity, the utility said.

PG&E said it invested billions of dollars to help the state of California meet its renewable power obligations. Those investments drove down the cost of wind and solar energy for its competition, PG&E said, but left the company still paying for the more expensive contracts.

“As a result, many of the utility’s agreements to procure renewable energy resources, which are typically long-term — 15- to 20-plus years in length — obligate the debtors at rates significantly higher than [those] currently available in the renewable resources market. On the contrary, other load serving entities, i.e., the debtors’ competitors, are able to procure required renewable energy resources at those lower rates.”

PG&E argued the only way for the companies to emerge from bankruptcy intact is for the court to allow the utility to abrogate overpriced contracts. It said any input from FERC over those contracts violates the court’s authority under the Bankruptcy Code.

In its filing, PG&E notes “recent changes in the energy landscape have significantly” altered its energy procurement needs for the future.

“In recent years, there has been a significant decrease in demand for [PG&E’s] electric supply service, which has resulted in [PG&E] providing less electricity to fewer customers,” the utility wrote. Chief among the causes are the growth of community choice aggregators, direct access and distributed generation, as well as the success of energy efficiency programs.

“Due to the incontrovertible economic significance of the debtors’ PPAs, as well as the continuously evolving competitive and regulatory factors affecting these agreements, the debtors’ PPA rejection and assumption decisions under section 365 of the Bankruptcy Code will play a vital role in the reorganized debtors’ post-emergence operations and financial profile,” PG&E’s lawyers wrote.

“As such, it is vital to a successful reorganization that the debtors’ determinations regarding whether to assume or reject their PPAs be assessed by this court pursuant to the business judgment standard to which any other debtor is subject.”

PG&E said it was primarily forced into bankruptcy by liability for massive wildfires in 2017 and 2018 that could top $30 billion. Wildfire victims and their advocates have argued PG&E was seeking bankruptcy protection to avoid their lawsuits, but PG&E insisted Tuesday that wasn’t the case.

Pacific Gas and Electric CFO Jason Wells | PG&E

“To be clear, the Chapter 11 cases are not a strategy or attempt to avoid PG&E’s responsibility for the heartbreaking and tragic loss of life, devastating damage and destruction to homes and businesses, and harm to the communities that has been incurred as a result of the 2017 and 2018 Northern California wildfires,” PG&E’s chief financial officer, Jason Wells, wrote in a court declaration.

The thousands of victims who are part of the 750 lawsuits filed against PG&E will now likely assume a status similar to unsecured creditors.

Shareholders, meanwhile, will have to take their chances. Investors often lose their stakes in bankruptcy, but PG&E shareholders emerged largely intact after the company’s 2001 bankruptcy in the wake of the state’s energy crisis. Whether that happens this time is highly uncertain and probably will remain so for much of the next two years, the time the bankruptcy is likely to play out.

One key difference: Unlike the previous bankruptcy that involved only the PG&E utility, this one covers its holding company as well.

14 Hours

The judge appointed to oversee the Chapter 11 proceeding in Northern California’s U.S. Bankruptcy Court pointed out that difference Tuesday during the first hearing in what promises to be a drawn-out process. Judge Dennis Montali would know. In 2001 he was picked to oversee PG&E’s prior reorganization.

Montali noted the sheer volume of the work already confronting his court.

“I want to repeat again something I made clear this morning … most of us have only had 14 hours to absorb what has been filed,” Montali said during the hearing, which began at 1:30 p.m. PG&E had filed for bankruptcy shortly after midnight. By the morning there were nearly 50 filings in the case.

The judge expressed regret that he wouldn’t be able to address the 17 motions already in the docket or hear statements from those with an interest in the outcome of PG&E’s bankruptcy.

“I’m trying to absorb everything quickly. I’m not going to listen to arguments [today],” he said.

Montali added he “feels very strongly” that the public should be able to weigh in on such a “high-visibility” case but that he couldn’t allow that during Tuesday’s hearings.

“I don’t mean to be [discourteous] or cut off people otherwise, but I can’t fit into the time frame anything,” he said.

Instead, Montali kept the hearing focused on the procedural issue of “what comes next” — namely the schedule going forward — and addressing the most immediate concerns of the parties before the next hearing, now slated for Thursday at 9:30 a.m.

Montali said some of the motions in the docket didn’t require immediate action, while pointing to a handful that did, including those related to maintaining current procedures around cash management, insurance policies, customer programs and employee wages. “The things that affect real people, like employees,” he said.

But Montali promised his court would review all the motions during Thursday’s hearing.

“The motions are fairly conventional, but the numbers are obviously much larger,” said Stephen Karotkin, an attorney with Weil, Gotsal and Manges, which is representing PG&E. “I think we were very careful to tailor for a smooth transition into Chapter 11.”

At Karotkin’s request, Montali issued orders temporarily granting the cash management request, as well as another motion intended to assure payments to natural gas and electricity exchange operators, such as CAISO. (CAISO issued a statement Tuesday saying the bankruptcy hadn’t caused any grid disruption.)

Another Weil attorney noted PG&E was seeking a preliminary injunction confirming the bankruptcy court’s exclusive jurisdiction over the debtors’ rights to reject PPAs and other FERC-regulated agreements. He said the company would need the court to act on that matter before FERC’s Feb. 25 deadline to respond to its Jan. 29 order on the issue.

“We don’t think we need to be there,” he said. “We need to be here.”

A Department of Justice attorney representing FERC piped up over the telephone: “The proceeding there is separate from the FERC one. FERC issued an order in its own jurisdiction. Nothing in this court could alter PG&E’s statutory obligation to respond to FERC.”

Montali urged PG&E’s attorneys to do what they needed to comply with FERC’s requirements until he ruled on the injunction.

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FERC Rejects NEPOOL Press Membership Ban

By Rich Heidorn Jr.

FERC on Tuesday rejected the New England Power Pool’s attempt to bar members of the press from membership but left intact — for now, at least — rules barring reporting on proceedings (ER18-2208-001).

The commission’s unanimous ruling appears to open the way for RTO Insider reporter Michael Kuser to join NEPOOL. But without additional action by the commission, he would be bound by NEPOOL’s rules barring members “from reporting on deliberations or attributing statements to other NEPOOL members.”

The commission said it would be ruling separately on RTO Insider’s Section 206 complaint, asking FERC to terminate the group’s stakeholder role or direct ISO-NE to adopt an open stakeholder process like those used by other RTOs (EL18-196). New England is the only one of the seven U.S. regions served by RTOs or ISOs where the press and public are prohibited from attending stakeholder meetings.

NEPOOL filed the request to bar members of the press from joining NEPOOL after Kuser, an electric ratepayer in Vermont, applied to join as an End-User Customer in March.

NEPOOL said the rule change was necessary because allowing the press to join would inhibit the group’s ability to foster candid discussions and negotiations that narrow and resolve complex issues. NEPOOL also contended FERC had no jurisdiction to reject the rule change.

Many of NEPOOL’s meetings are held at the Westborough, Mass., DoubleTree Hotel. | Google

Unduly Discriminatory

FERC said, however, it did have jurisdiction, and the proposed change was unduly discriminatory.

“The NEPOOL press amendments deny NEPOOL membership to members of the press who serve any role directly connected with news collection and reporting. Because some such members of the press otherwise would be eligible for NEPOOL membership as end-use participants, this prohibition unjustly denies them the ability to vote on NEPOOL matters despite their stake in the outcome,” the commission said.

“NEPOOL’s primary argument in support of excluding the press from NEPOOL membership relates to concerns with the reporting of stakeholder discussions. We find, however, that the record does not support the contention that allowing members of the press to become participating NEPOOL members will inhibit NEPOOL’s operations or undermine stakeholder deliberations. The Participants Committee Bylaws and Standard Conditions currently in place — which this order does not affect — already prohibit all NEPOOL members from reporting on deliberations or attributing statements to other NEPOOL members. NEPOOL has not demonstrated that barring members of the press from exercising the privileges unique to NEPOOL membership — i.e., attending, speaking, and voting at NEPOOL meetings — will meaningfully advance its aim for candid deliberation in light of these existent provisions. The NEPOOL press amendments do, however, as discussed above, prevent the participation of individuals otherwise eligible for membership solely based on their profession.”

[Editor’s Note: Kuser and RTO Insider told NEPOOL officials his application was intended to provide him a means to cover stakeholder meetings, and he did not intend to take policy positions or vote.]

Jurisdiction

FERC said NEPOOL’s membership rules were within the commission’s jurisdiction because they directly affect commission-jurisdictional rates, noting that the group’s votes “both signal to the commission stakeholder approval of ISO-NE proposals and have the potential to generate alternative ‘jump ball’ proposals for commission consideration.”

The order said it was acting consistent with commission precedent. “The commission has found that the stakeholder process within an RTO/ISO ‘is a practice that affects the setting of rates, terms, and conditions of jurisdictional services of the type that the Supreme Court has held falls within the commission’s jurisdiction,’” it said, quoting from a 2016 order involving PJM.

Remaining Questions

The commission’s ruling gave no indication how, or when, it will rule on RTO Insider’s complaint, which was filed two weeks after NEPOOL’s proposed rule change.

RTO Insider contended nonpublic meetings violate the public interest and the missions stated in ISO-NE’s and NEPOOL’s governing documents.

It also contested NEPOOL’s assertion that it is a private organization, saying FERC precedent “hardwires the NEPOOL stakeholder process into the regulatory process by requiring its use.”

RTO Insider said if the power pool can justify its press ban as a “private” entity desiring secrecy, “its special powers and privileges should be transferred to an open stakeholder process within ISO-NE, and the ISO-NE resources devoted to NEPOOL (currently $2.6 million annually) should be devoted to an open stakeholder process within ISO-NE.”

Reaction

“An occasion for dancing in the streets!” tweeted New Hampshire Consumer Advocate D. Maurice Kreis, who had opposed the ban.

Another opponent of the ban, Tyson Slocum, director of Public Citizen’s Energy Program, was less jubilant, calling it “a partial victory for the public and the freedom of the press.”

“It is outrageous that, despite today’s FERC order, NEPOOL is still free to ban the general public from attending meetings, and journalists cannot attend meetings unless they pay a membership fee. FERC-jurisdictional proceedings, where billions of dollars in electric rate policy are developed, must be freely open to the public and the media,” he said.

Miles Farmer, an attorney for the Natural Resources Defense Council, said the ruling is important “because NEPOOL’s deliberations affect New England customers’ energy prices as well as the mix of technology types that supply the region.”

“ISO New England is the only regional grid operator that has closed its door on press access to its stakeholder meetings — meetings where key decisions are made about the Northeast’s electricity supply,” said Mike Jacobs, senior energy analyst at the Union of Concerned Scientists (UCS), which had opposed the NEPOOL proposal. “The need for public debate and awareness of pending energy decisions is of paramount importance as a society faces a changing climate. It’s good to see FERC cast a vote against this proposal and in favor of a little more transparency and accountability in New England’s power planning process.”

NEPOOL Chair Nancy P. Chafetz, the New England director of market intelligence for Customized Energy Solutions, did not immediately respond to a request for comment.

NEPOOL Secretary David Doot responded to the order with a memo to NEPOOL members, saying “the Membership Subcommittee will meet to consider the pending application from the RTO Insider press reporter and recommend to the Participants Committee whether any additional conditions should apply to such a membership.”

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SPP Regional State Committee Briefs: Jan. 28, 2019

By Tom Kleckner

Commission Staff Not Yet to Agreement on Cost Allocation Issues

NEW ORLEANS — Regulatory staffers have been unable to reach a consensus on possible revisions to cost-allocation rules for wind-rich areas and may table their year-long review, the Nebraska Power Review Board’s John Krajewski told the Regional State Committee Monday.

January’s Regional State Committee meeting | © RTO Insider

The Cost Allocation Working Group, which reports to the RSC, is considering changes to SPP’s highway/byway framework, which considers transmission facilities of 300 kV or more as highway infrastructure, with their costs allocated on a regionwide, postage-stamp basis. Facilities between 100 kV and 300 kV are categorized as byway facilities, with two-thirds of the cost assigned to the host zone and one-third allocated regionwide. Projects less than 100 kV are allocated entirely to the host zone.

Among its options, the CAWG is considering changing the 100-300-kV allocation percentage to 50% or 66% as it ponders different ways of charging for load.

The working group is also evaluating whether to consolidate transmission zones for the SPP Tariff’s Schedule 11 charges, which cover transmission construction costs. Krajewski said zones encompassing diverse areas that include wind and non-wind zones would spread byway costs over a larger footprint.

Other options include modifying the 300-kV and less allocation percentage in wind-rich zones only and using a generation-injection rate applicable to all generation or just a subset.

CAWG Chair Cindy Ireland updates the RSC. | © RTO Insider

“As we’ve worked through this, I’ve worked on the assumption there was a problem and it needed to be fixed,” Krajewski said. “Some of my fellow CAWG members haven’t reached that point yet.

“If there isn’t a consensus [that] there’s a problem [at the group’s next meeting], we’ll put away what we’ve worked on. If we reach a point where there is a problem, I would like to see ourselves narrow those options to two or three, where we can give some detailed analysis,” he said. The CAWG’s next meeting is a conference call set for Feb. 12.

Should it come to an agreement, the CAWG plans to turn its work into a white paper and make recommendations to the RSC and the Holistic Integrated Tariff Team, which is taking a broader look at cost allocation. (See “HITT Educates MOPC on its Progress, Learnings,” SPP Markets & Operations Policy Committee Briefs: Jan. 15, 2019.)

“Those two processes need to be wedded up and worked together,” Texas Public Utility Commission Chair DeAnn Walker said of the CAWG and HITT work. “I understand there’s serious disagreement over whether there’s a problem, but there’s a lot of overlapping things here with the HITT that need to be worked on together.”

SPP, MISO Regulators in Educational Phase

Kansas Corporation Commissioner Shari Feist Albrecht told the RSC that MISO and SPP regulators working on the RTOs’ seam issues are still in the midst of their educational phase.

“We’re suffering from some beginning-to-operate-jointly pains,” said Albrecht, who represents SPP regulators on the SPP-RSC/OMS Liaison Committee.

The committee was created last year to work with SPP and MISO to improve market-based transactions and operations across the seam. (See Regulators Examine MISO, SPP Seams Issues at NARUC.)

Albrecht and Missouri Public Service Commissioner Daniel Hall moderated a panel discussion on seam issues during a recent Mid-America Regulatory Conference meeting. The committee will next meet Feb. 10 on the sidelines of the National Association of Regulatory Utility Commissioners’ winter policy summit, where it will discuss the stakeholder responses and the potential need for FERC or independent analyses.

South Dakota’s Kristie Fiegen jokes with Kansas’ Shari Feist Albrecht (left) much to the amusement of Missouri’s Scott Rupp and RSC Chair Kim O’Guinn (right) of Arkansas. | © RTO Insider

New Mexico’s Byrd Joins RSC

The RSC welcomed Jefferson “Jeff” Byrd as its New Mexico representative. He replaces Pat Lyons, who left the regulatory arena last year.

A rancher and environmental engineer, Byrd won election in November to one of five seats on the New Mexico Public Regulation Commission. It’s the first time he has held public office, following two unsuccessful runs at the U.S. House of Representatives.

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FERC Claims Authority over PG&E Contracts in Bankruptcy

By Hudson Sangree

FERC said it shares authority with the federal bankruptcy court over any power purchase agreements Pacific Gas and Electric seeks to modify after filing for bankruptcy, as the utility did on Tuesday.

The commission ruled Friday in a petition by NextEra Energy (EL19-35) and on Monday in response to one by Exelon (EL19-36).

As part of its bankruptcy filing, PG&E asked the U.S. Bankruptcy Court on Tuesday to issue an injunction confirming its exclusive jurisdiction over the debtors’ rights to reject PPAs and other FERC-regulated agreements. (See related story, PG&E Files for Bankruptcy.)

The issue arose after NextEra and Exelon petitioned FERC for declaratory orders against PG&E because it was concerned, as many generators have been, that the utility would try to get out of high-cost contracts it had signed with owners of solar, wind and other renewable electricity sources.

NextEra’s and Exelon’s subsidiaries sell wind and solar energy to PG&E.

In its petition, NextEra asserted that the Federal Power Act created “a comprehensive regulatory framework for protecting the public interest” and entrusted the commission with “the authority to implement that framework.”

“According to NextEra, the core of the commission’s regulatory responsibilities under the FPA is the exclusive authority to regulate the rates, terms and conditions for interstate transmission and wholesale sales of electric energy under FPA Sections 205 and 206.8,” FERC wrote.

NextEra is concerned about its solar and wind power purchase agreements with PG&E if the utility enters bankruptcy. | NextEra

The commission explained that to protect its wholesale PPAs, “NextEra requests that the commission issue an order finding PG&E may not abrogate, amend or reject its commission-jurisdictional wholesale power purchase agreements with NextEra in any bankruptcy proceedings that may be initiated by PG&E without first obtaining approval from the commission under FPA Sections 205 or 206.6.”

NextEra cited the filed-rate doctrine to argue that rates filed and approved by FERC have the authority of federal regulations and cannot be undone except with FERC approval.

Dozens of generators and other entities filed motions to intervene and comments in support of NextEra’s petition. They include the 550-MW Topaz Solar Farms, in central California, one of the nation’s largest solar installations. Topaz, owned by Berkshire Hathaway Energy, saw its credit rating cut to junk status this month because it had an exclusive 25-year PPA with PG&E. (See PG&E Credit Woes Spread, Worrying CAISO Members.)

PG&E argued that a FERC order limiting its rights prior to its bankruptcy filing would violate the FPA and the U.S. Bankruptcy Code.

PG&E also contended that “NextEra’s petition is speculative and hypothetical because PG&E’s bankruptcy has not yet occurred and no action has been taken with regard to any particular contract. Additionally, PG&E claims that the commission’s jurisdiction under the FPA applies to the sale, but not the purchase, of power, and by extension, to sellers, but not buyers, of power. Accordingly, PG&E states that the commission is not authorized to order a buyer to continue to purchase power.”

FERC acknowledged that the law was unsettled when it came to contested authority between the FPA and Bankruptcy Code and between FERC and the courts. It took a middle road, saying the commission and courts share authority in cases like PG&E’s.

“Against this background, and given the unsettled state of the law, we have reviewed the FPA and Bankruptcy Code in light of the arguments raised in the petition and conclude that this commission and the bankruptcy courts have concurrent jurisdiction to review and address the disposition of wholesale power contracts sought to be rejected through bankruptcy,” FERC wrote.

“We find that to give effect to both the FPA and the Bankruptcy Code, a party to a commission-jurisdictional wholesale power purchase agreement must obtain approval from both the commission and the bankruptcy court to modify the filed rate and reject the contract, respectively.”

In a research note issued to its clients Saturday, ClearView Energy Partners said FERC’s order did not bar PG&E from seeking to reject its PPAs before obtaining the commission’s approval.

“Instead, we read last night’s order as FERC asserting that as a generic matter such contract abrogation in the bankruptcy context would eventually require its approval,” the research firm said.

ClearView said the commission was taking the position established in the Boston Generating bankruptcy proceeding, where the litigating parties agreed that FERC and the U.S. district court had concurrent jurisdiction over changes to PPAs.

It concluded that “we continue to expect that PG&E may not have a free hand to reject the PPAs it currently holds,” specifically those signed with renewable resources needed to meet California’s public policy objectives.

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PG&E Files for Bankruptcy

By Rich Heidorn Jr.

As expected, PG&E Corp. and its primary operating unit, Pacific Gas and Electric, filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code this morning.

The company said the filing in the U.S. Bankruptcy Court for the Northern District of California is an effort to provide “the orderly, fair and expeditious resolution of its liabilities resulting from the 2017 and 2018 wildfires.”

It said it made the filing after taking into account California officials’ statements last week clearing it of liability for the 2017 Tubbs Fire. (See related story, PG&E Cleared in Fire that Burned Santa Rosa.)

PG&E said it will continue operations during bankruptcy proceedings. | PG&E

The parent company listed total assets of $71.4 billion and debts of $51.7 billion. But those debts do not include all the expected wildfire claims. Its list of its 50 biggest creditors is dominated by banks, led by the Bank of New York Mellon and Citibank.

PG&E also filed a complaint asking the court to issue an injunction confirming its exclusive jurisdiction over the debtors’ rights to reject power purchase agreements and other FERC Claims Authority over PG&E Contracts in Bankruptcy.)

“Our most important responsibility is and must be safety, and that remains our focus. Throughout this process, we are fully committed to enhancing our wildfire safety efforts, as well as helping restoration and rebuilding efforts across the communities impacted by the devastating Northern California wildfires,” interim PG&E Corp. CEO John R. Simon said in a statement released shortly after midnight. “We also intend to work together with our customers, employees and other stakeholders to create a more sustainable foundation for the delivery of safe, reliable and affordable service in the years ahead. To be clear, we have heard the calls for change, and we are determined to take action throughout this process to build the energy system our customers want and deserve.”

PG&E asked the court’s approval to sign a $5.5 billion in debtor-in-possession financing agreement to allow the company to continue maintenance and investments in safety and reliability during the bankruptcy proceedings. JPMorgan Chase, Bank of America, Barclays, Citi, BNP Paribas, Credit Suisse, Goldman Sachs, MUFG Union Bank and Wells Fargo will act as joint lead arrangers.

“We believe that this process will make sure that we have sufficient liquidity to serve our customers and support our operations and obligations,” Simon said.

PG&E also filed motions seeking court approval to pay employees’ wages and benefits and continue its support of existing customer programs for energy efficiency and low-income ratepayers. The company said it will pay suppliers in full for goods and services provided going forward.

The company named James Mesterharm and John Boken, managing directors at AlixPartners, as chief and deputy chief restructuring officers, respectively.

PG&E shares, which closed Monday at $12.01, were up slightly in pre-market trading today.

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MISO Moving Quickly on Initial SATA Rules

By Amanda Durish Cook

CARMEL, Ind. — MISO and stakeholders are hoping to complete policies allowing storage to qualify as transmission for the RTO’s 2019 Transmission Expansion Plan (MTEP 19).

The RTO hopes to file its first plan to allow storage as a transmission asset (SATA) with FERC by June. Initially, proposed SATA will only be allowed to solve transmission reliability needs and will be ineligible to simultaneously participate in MISO’s energy markets. The RTO currently has one reliability-based storage project proposal lined up for evaluation in MTEP 19.

John Fernandes | © RTO Insider

“This storage-as-transmission [development] process is really short. … Folks want to get this right. Backtracking on policy once it’s been filed and accepted isn’t impossible, but it’s a really heavy lift,” Energy Storage Task Force Chair John Fernandes said during a Jan. 24 meeting. Fernandes commended MISO’s initiative on envisioning storage in the transmission realm, saying it is one of the first markets nationwide to do so.

“Storage might be able to go in where others can’t due to permitting,” Customized Energy Solutions’ David Sapper said.

The Energy Storage Task Force will hold a workshop on storage functioning strictly as transmission on Feb. 14. Ahead of the workshop, Fernandes urged stakeholders to think about how such projects would advance through the MISO stakeholder process and what criteria they might have to meet.

No Mixed-mode SATA, yet

MISO Director of Planning Jeff Webb said the RTO is choosing to “carve up” the SATA concept into less complex uses so it can better understand it and plan incremental approaches.

For now, MISO is proposing that SATA function solely as transmission — solving thermal, voltage or stability issues — and precluding it from energy market participation. MISO said it will develop rules for mixed-mode SATA use later. “We don’t know how to mix those two just yet,” Webb said.

Because mixed-use storage will not be permitted at first, the RTO will not require SATA to enter its generation interconnection queue. However, MISO does plan to model previously approved SATA in its interconnection studies. It said it will consider SATA’s “capabilities to inject or withdraw energy as needed to best mitigate reliability issues” as part of the network upgrades study during the definitive planning phase study in the queue.

SATA will also be modeled in MTEP reliability studies. MISO said it will gauge a proposed SATA project’s ability to “resolve the identified transmission issue at specified critical system conditions, consistent with the facility design capabilities.”

MISO said it will also create a special interconnection agreement among it, the storage owner, and the transmission system that the SATA is connected to. SATA operators must also complete MISO’s market participant registration.

Invenergy’s 31.5-MW Grand Ridge Energy Storage project | Invenergy

MISO in Functional Control

MISO proposes SATA be compensated like other transmission owners, with the storage facilities under the functional control of the RTO. MISO said keeping functional control of SATA will be practical as storage owners inevitably transition to mixed-mode use.

“MISO contemplates that most SATA will eventually desire to participate in markets in addition to providing cost-based transmission services. The ability to coordinate use of the asset in this mixed mode requires MISO as market operator to instruct the charging and discharging of the SATA for the provision of transmission services,” the RTO said. “Independent market operator control of the device for transmission service purposes will enable accounting for energy injections and withdrawals whether such transactions are instructed by MISO for transmission service purposes or as cleared market transactions. Further, control of the device by MISO for transmission purposes will mitigate concerns about inappropriate use of the device to the advantage of any particular market participant.”

Hisham Othman, of transmission and distribution consulting firm Quanta Technology, said reliability should always take precedence over any market benefits for mixed-mode SATA. He also said reliability requires very fast SATA controls, able to respond within a millisecond following a contingency to restore voltage and mitigate line overloads.

After stakeholder questioning, Webb said MISO will seek to quantitatively evaluate the benefits of SATA in the MTEP process as it’s able to recognize them. “If we can understand them and repeat them, then we’ll document them,” he said.

Some stakeholders asked if MISO might evaluate storage projects based on how mobile they might be. But Othman said there’s upgrade costs to be considered when a storage asset is physically moved to serve another area. “The reality is there’s a cost to picking it up and moving it.”

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PJM MRC/MC Briefs: Jan. 24, 2019

By Christen Smith and Rich Heidorn Jr.

Markets and Reliability Committee

Revisions on Incremental Capacity Transfer Rights Endorsed

WILMINGTON, Del. — The Markets and Reliability Committee on Thursday endorsed a change to align PJM’s Tariff with manual language on the process for requesting incremental capacity transfer rights (ICTRs) calculations.

Steve Herling, PJM vice president of planning, said the “very limited” change requires new service customers to request the calculations during the facilities study phase and limits each request to no more than three locational deliverability areas.

The change comes in response to a FERC order that found PJM had not been following section 234.2 of the Tariff for assigning ICTRs. The RTO had clarified the procedure in Manual 14E: Upgrade and Transmission Interconnection Requests, but FERC said it must also be added to the Tariff (EL18-183).

The Tariff requires the RTO to identify the increase in the capacity emergency transfer limit (CETL) resulting from an interconnection, merchant transmission facility or customer-funded upgrade.

“As a practical matter, it would be impossible for us to calculate the increased CETL for every generator in the queue,” Herling said, citing estimates that it would take 54 hours per case to study deliverability to all 27 load delivery areas. “Bottom line is, for us to keep putting out system impact studies in compliance with the Tariff, we have to make to a change. Either we will have to stop putting out studies, or projects will be significantly delayed.”

The MRC on first read unanimously endorsed the change, which also was approved unanimously by the Members Committee later Thursday.

Markets and Reliability Committee Secretary Dave Anders and Chair Suzanne Daugherty | © RTO Insider

Fuel Security Issue on Tap for Feb. MRC

PJM will present the first read of a problem statement and issue charge on Phase 2 of its fuel security initiative at the February MRC, with a vote targeted for March, PJM’s Tim Horger said.

The RTO will recommend assigning the issue to a new senior task force reporting to the MRC. Among the issues to be discussed will be attributes that define a fuel-secure resource, whether a minimum quantity of fuel-secure resources is necessary, and market and operational mechanisms that could ensure fuel security.

Horger said PJM will be seeking a market-based solution, potentially through changes to the capacity market.

In mid-January, the RTO published 324 scenario templates from the fuel security analysis it released in December, which concluded that it should take “proactive measures” to value fuel security attributes of its generators.

The analysis found that “on-site fuel inventory, oil deliverability, availability of non-firm natural gas service, location of a pipeline disruption and pipeline configuration become increasingly important as the system comes under more stress.” (See Full PJM Study Makes Case for Fuel Security Payments.)

The RTO hopes to make a FERC filing in December or early 2020, Horger said.

The issue is likely to spark a renewed battle between supply and load interests. Tom Rutigliano, representing the Natural Resources Defense Council, said the issue should first be dealt with under the Capacity Performance program, noting that many risk factors listed in PJM’s analysis are unit-specific and thus part of generators’ CP obligations.

Although PJM acknowledged no individual generator could address systemic risks such as pipeline breaks or cyberattacks on supply systems, “the risks found in their study are mostly interruptible fuel contracts and lack of trucks, both of which can be solved by individual generation owners,” Rutigliano explained later. “Pipeline breaks play a relatively small component in the study results.”

Manuals Approved

The MRC unanimously endorsed the following manual changes:

PJM’s Adam Keech also notified members of a change made earlier this month to Manual 11: Energy & Ancillary Services Market Operations to clarify the current procedure regarding transient shortage pricing.

Keech said the manual did not fully describe the process for determining reserve shortages. He said the RTO became aware of the issue following a July 10 incident in which its area control error fell to -2,942 MW with a low frequency of 59.903 Hz.

PJM determined the low frequency resulted from several causes, including multiple unit trips, non-approved cases from real-time security-constrained economic dispatch and poor synchronized reserve response.

Members Committee

Members approved a revised definition of “on-site generators” in the market participation rules in the Tariff and Operating Agreement. The new definition recognizes that behind-the-meter resources can participate as both demand response to reduce load and as generation to inject power.

FTR Mark-to-auction Credit Requirements OK’d

With one objection, the committee approved a new a mark-to-auction component for financial transmission rights credit requirements, a change prompted by the GreenHat Energy default.

Although a decline in market value can indicate increasing FTR risk, PJM’s rules do not provide for a collateral call when an FTR portfolio’s value is deteriorating. The change would consider the difference between the FTR purchase price and most recent market price. It cleared the MRC in December. (See “FTR Collateral,” PJM Market Implementation Committee Briefs: Dec. 12, 2018.)

The mark-to-auction rules chosen by PJM stakeholders (package G1) would affect only 4% of accounts, excluding GreenHat Energy. | PJM

Opportunity Cost Calculator Manual Revisions

Members endorsed revisions to Manual 15: Cost Development Guidelines governing generators’ use of the Independent Market Monitor’s calculator as an alternative method of calculating energy market opportunity costs.

A vote on related revisions to Schedule 2 of the OA was deferred again, until February. (See “Opportunity Cost Calculator Vote Deferred,” PJM MRC/MC Briefs: Oct. 25, 2018.)

Liaison Committee Meetings to Change

Members heard the first read of a charter revision that would require the scheduling of Liaison Committee meetings with the Board of Managers before the board’s regular meeting. Under current rules, Liaison Committee meetings alternate between before and after the board meeting. The change came out of discussions at the Stakeholder Process Forum.