The cost of GreenHat Energy’s default could rise by $250 million to $300 million if PJM is forced to unwind settlements of the company’s financial transmission rights portfolio, PJM Chief Financial Officer Suzanne Daugherty said Thursday. That could push the total cost of the company’s collapse to at least $430 million, Daugherty said.
PJM said it will seek a stay of FERC’s Jan. 30 order rejecting a waiver of the RTO’s liquidation rules and requiring it to resettle five months of FTRs that the commission said should have been liquidated sooner (ER18-2068).
In an email to members, Daugherty said the commission’s ruling would have a dire impact on members and consumers.
“The waiver request was based on the legal vehicles and FERC precedents in effect to stop liquidation in an auction that was dysfunctional and which certainly would have resulted in unjust and unreasonable rates,” she said.
FERC’s order requires PJM to rerun the cleared July 2018 FTR auction and liquidate a “significant portion” of the FTR positions from the GreenHat portfolio for September 2018 through May 2019, PJM said. It also requires the RTO to unwind the default allocations and related settlements made for GreenHat FTRs that went to settlement since September 2018.
The resettlements would “likely place a number of members in breach of their collateral requirements of PJM’s credit policy and require them to fulfill a collateral call within two business days based on the unanticipated changes in the positions in members’ FTR portfolios that would result from changing the cleared results of the July 2018 FTR auction,” Daugherty said.
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.” The RTO said a slower liquidation of the company’s large portfolio would reduce losses to members.
But FERC said PJM’s request would affect the outcome of the July FTR auction “as well as parties’ confidence in the rules governing future proceedings.”
The commission also rejected PJM’s request to retain $550,000 in collateral posted by one of GreenHat’s principals through a second company (ER18-1972).
PJM said it will ask FERC to rehear the waiver case and seek a stay on the order in the interim. Asked when the stay request would be filed, PJM spokesman Jeff Shields said, “We are still considering our legal options.”
LaFleur on Thursday announced she was “no longer seeking” a third term and would leave the commission by the end of the year.
LaFleur, who has served on the commission since July 13, 2010 — longer than all her colleagues’ tenures combined — said she would stay until at least June 30, the end of her current term, “and probably longer, depending on my future plans and the possible appointment of a successor.”
Senate leadership informed the commissioner Tuesday that President Trump would not nominate her for another term, according to Andrew Holleman, LaFleur’s communications and policy analyst. By law, she can stay on the commission past June 30 until a replacement is sworn in or until the end of the current session of Congress.
“She’s said all along it wasn’t her decision, so she figured she would make an announcement as soon as she heard,” Holleman said in an email.
“While this is not the outcome I had hoped for, I feel very lucky to have served on FERC for more than eight years (and counting),” LaFleur said in a statement. “It has been a high honor to serve at the commission, and I love working here. I have many people to thank for the opportunities I’ve had and will certainly have more to say as I get closer to actually leaving.”
LaFleur declined further comment. A FERC spokesperson declined to comment.
With the departure of Robert Powelson in July and the death of Commissioner Kevin McIntyre on Jan. 2, FERC would be left with three commissioners after LaFleur’s departure. A spokeswoman for Sen. Lisa Murkowski (R-Alaska), chair of the Senate Energy and Natural Resources Committee, said she has not heard anything from the White House regarding its plan for replacement nominees. Holleman also said he had not heard anything.
A Constant Presence
Nominated by President Barack Obama, LaFleur’s tenure has been marked by frequent upheavals in the commission’s roster.
She came to the commission after more than two decades in the electric and natural gas industry, including a stint as executive vice president and acting CEO of National Grid USA.
LaFleur became acting chair of the commission after the resignation of Jon Wellinghoff in 2013, and she was nominated by Obama for a second term in 2014. The president also nominated Norman Bay, then director of the commission’s Office of Enforcement, as chair, but members of the ENR Committee protested, citing Bay’s lack of regulatory experience and the gender politics of his ascension over LaFleur. This led to an unusual deal between the Senate and the White House, in which LaFleur became the chair for nine months while Bay served as commissioner. (See Senate Confirms Bay, LaFleur.)
Bay took over the chair in April 2015. But he resigned shortly after Trump’s inauguration in January 2017, when the new president named LaFleur acting chair again until a Republican could be sworn in. The GOP seats were empty after Philip Moeller and Tony Clark left the commission in October 2015 and September 2016, respectively.
Bay’s resignation also left the commission without a quorum to issue orders and decisions, which would last for six months until the arrival of Republicans Chatterjee and Powelson in August 2017. After the resignation of Colette Honorable in June 2017, LaFleur was briefly the lone commissioner.
The commission has been split along party lines for nearly a year over the consideration of greenhouse gas emissions in gas infrastructure approvals. Following an August 2017 ruling by the D.C. Circuit Court of Appeals that said FERC must consider the impact of greenhouse gas emissions when licensing gas pipelines, LaFleur has sided with fellow Democrat Richard Glick in voting against certain projects. (See Dem Dissents Show FERC Divide on Carbon.)
With the departure of Powelson and the death of McIntyre after months of battling brain cancer that kept him from voting, Chairman Neil Chatterjee has pulled gas items from the consent agenda at open meetings.
LaFleur’s announcement brought accolades on Twitter.
“She epitomizes what public service is all about,” Glick said.
“Her measured, fair and knowledgeable approach at FERC will be missed,” said Theodore Paradise, senior vice president of transmission strategy for Anbaric.
“An exceptional servant and thoughtful leader who withstood what one of the most trying and yo-yoing of any FERC tenure,” said Dan Dolan, president of the New England Power Generators Association.
“She has been a tremendous role model to me and countless other women in the energy industry,” said Shannon Maher Bañaga, director of federal affairs for TECO Energy. “‘Thank you’ isn’t enough.”
NERC has recommended a $10 million fine on an unidentified utility for repeated violations of critical infrastructure protection (CIP) reliability standards over more than three years that exposed a “lack of management engagement, support and accountability.”
In a Notice of Penalty filed Jan. 25, NERC cited 127 violations between 2015 and 2018 (52 posing “minimal” risk, 62 “moderate” and 13 “serious”). While most of the violations were self-reported, others resulted from compliance audits.
Although many of the details were redacted as critical energy/electric infrastructure information (CEIl), the document refers to “companies” and “regional entities” in the plural, suggesting a large, multistate utility was involved.
“The 127 violations collectively posed a serious risk to the security and reliability of the [bulk power system]. The companies’ violations of the CIP reliability standards posed a higher risk to the reliability of the BPS because many of the violations involved long durations, multiple instances of noncompliance, and repeated failures to implement physical and cybersecurity protections,” NERC said. “As an example, the companies’ failure to accurately document and track changes that deviate from existing baseline configurations increased the risk that the companies would not identify unauthorized changes, which could adversely impact [bulk electric system] cyber systems.”
The notice cited as contributing causes “disassociation of compliance and security that resulted in a deficient program and program documents, lack of implementation, and ineffective oversight and training.”
It also criticized “organizational silos” illustrated by a lack of communication between management levels and “a lack of awareness of the state of security and compliance.”
There were also silos across business units “that resulted in confusion regarding expectations and ownership of tasks, and poor asset and configuration management practices,” NERC said.
In a settlement, the companies agreed to pay the fine and to improve their performance by increasing senior leadership involvement and oversight; creating a centralized CIP oversight department; and restructuring roles to focus on standards, enterprise oversight, enterprise CIP tools, compliance metrics and regulatory interactions. They also agreed to conduct industry surveys and benchmark discussions to develop best practices.
The companies also agreed to invest in enterprise-wide tools for asset and configuration management, visitor logging, access management, configuration monitoring and vulnerability assessments; increase training; and institute annual compliance drills.
NERC said the penalty was based on the companies’ “repeat noncompliance” and “deficient” compliance program, mitigated by the lack of evidence of any attempt to conceal the violations. The settlement and fines are subject to approval by FERC.
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.”
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.”
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.)
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 Journalarticle 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.
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&EFiles 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.
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.”
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.
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.
“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.
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.
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.
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.
