A trial that could conclude the bankruptcy of Pacific Gas and Electric began Wednesday via videoconference, with the judge presiding from his breakfast room.
PG&E’s Chapter 11 case is the sixth-largest bankruptcy in U.S. history and by far the largest of any energy utility. The COVID-19 crisis has forced it to be decided by U.S. Bankruptcy Court Judge Dennis Montali from his home, with lawyers arguing from remote locations.
The “confirmation” proceedings to approve or deny PG&E’s proposed reorganization plan lasted just an hour on the first day, with only one witness called.
Judge Dennis Montali confers with lawyers for PG&E and fire victims by Zoom video on May 27.
Christina Pullo, a vice president with claims administrator Prime Clerk, testified about the results of voting on the plan that concluded May 15. Nearly 87,000 wildfire claimants were eligible to vote along with tens of thousands of other creditors, she said.
Pullo confirmed the results of the vote, previously filed in court papers, that showed at least 85% of fire victims and an overwhelming majority of other creditors approved of PG&E’s reorganization plan. That plan, valued at close to $60 billion, includes $13.5 billion for fire victims, $11 billion for the insurance companies and hedge funds that hold third-party subrogation claims, and $1 billion in compensation to local governments for fire-related expenses. (See PG&E Bankruptcy Moves Toward Conclusion.)
The company plans to issue nearly $26 billion in new stock to help pay for the plan.
Pullo faced cross-examination by William Abrams, a wildfire victim who has represented himself throughout the proceedings. Abrams has repeatedly said he opposes the plan because it doesn’t do enough to ensure victims get paid or to force PG&E to become a safer utility.
On Wednesday, he asked Pullo about alleged voting irregularities and about Prime Clerk’s connection to PG&E via its parent company Duff & Phelps, which Abrams said holds a sizable stake in PG&E. As a non-lawyer, his questioning was frequently interrupted by instructions from the judge and objections from some of the dozen or so attorneys who participated in the hearing.
Court clerk Lorena Parada swears in witness Christina Pullo of Prime Clerk at the start of the trial.
Should Montali approve PG&E’s plan, it would end a bankruptcy that started 16 months ago, when the company filed for Chapter 11 protection and reorganization in January 2019 as it faced up to $30 billion in wildfire liabilities.
State fire investigators determined the utility’s transmission lines ignited massive fires in 2015, 2017 and 2018 that combined killed more than 100 people and destroyed some 25,000 structures.
The fires included the Camp Fire, the largest in state history, that killed 85 residents and leveled more than 14,000 homes in and around the town of Paradise, Calif., in the Sierra Nevada foothills.
Critics have accused PG&E of funneling profits to shareholders rather than maintaining aged infrastructure, such as the century-old Caribou-Palermo line that sparked the Camp Fire.
The California Public Utilities Commission levied a record $1.9 billion in penalties on PG&E for its maintenance and safety failures. The commission is required to approve the utility’s Chapter 11 plan under state law, with a vote scheduled Thursday.
The bankruptcy proceedings are scheduled to continue through next week.
NERC is seeking comments through July 10 on proposed changes to its Rules of Procedures (ROP) that were ordered by FERC earlier this year in response to the ERO’s five-year performance assessment (RR19-7).
The planned updates apply to Section 1003, covering NERC’s infrastructure security program — particularly the Electricity Information Sharing and Analysis Center (E-ISAC) — and its sanction guidelines in Appendix 4B of the ROP.
Clarity Sought on E-ISAC’s Role
In its January order, FERC said that despite its growing share of NERC’s budget — accounting for 28% of NERC’s total 2020 budget and 26% of the projected budget for 2021 — the E-ISAC program lacks transparency. The commission requested that NERC clarify the E-ISAC’s relationship with the Electricity Subsector Coordinating Council (ESCC), correct inconsistencies in terminology used in the ROP and update other operational practices related to NERC’s infrastructure security program. (See NERC Wins Another 5 Years as ERO.)
To address FERC’s order, NERC made a number of additions to Section 1003, along with revisions to existing language. Significant insertions include a paragraph describing the role of the E-ISAC and its place alongside the Department of Energy and ESCC in the U.S. national security framework, expanding on a less detailed description in the current version of the ROP. The organization also added language emphasizing that it considers security an equal priority to reliability and resilience.
In addition, language stating that NERC “[fills] the role of the [ESCC]” was deleted. The new wording says that the organization “shall coordinate with” the council.
References to the critical spare transformer program, the National Infrastructure Protection Plan, vulnerability assessments of certain systems and working with the National SCADA Test Bed and Process Control Systems Forum were also deleted, as NERC is not involved in these activities anymore.
Sanction Changes Emphasize Fairness
The changes to the sanction guidelines in Appendix 4B clarify NERC’s and regional entities’ application of base penalties, in addition to emphasizing NERC’s focus on violation risk factor and severity level when determining penalty amounts. NERC also expanded on the role non-monetary sanctions may play in determining the final penalty amount.
Additional changes ordered by FERC include language requiring NERC and regional entities to ensure that “violators do not consider the imposition of monetary and/or non-monetary sanctions to be an economic choice or cost of doing business” by considering the size of the offender and its ability to pay when setting a penalty. The new language also stressed that penalties on multiple subsidiaries of a parent corporation that commit the same violation must be proportionate to the seriousness of the violation and the size of the offender.
Presentation Planned for August Board Meeting
FERC’s order in January mandated NERC make a compliance filing with the necessary revisions by July 21, but NERC requested an extension on the deadline in February that it said would allow for the full 45-day stakeholder comment period, as well as providing time for the Board of Trustees to review the changes before its meeting Aug. 20. (See NERC Seeks More Time on Rule Changes.)
FERC approved this request March 1, granting NERC until Aug. 28 for the compliance filing. The commission later extended the deadline again to Sept. 28 in light of the COVID-19 pandemic. (See FERC ExtendsNERC Compliance Filing Deadline Again.)
A separate compliance filing ordered by FERC — which requires NERC to detail audits of regional entities in the past five years or provide a plan for performing them within the next 18 months — was delayed to June 1.
Mexico’s government has been chipping away at the country’s electricity market reforms ever since Andrés Manuel López Obrador assumed the presidency in December 2018.
Mexican President Andrés Manuel López Obrador | Office of the Presidency
A planned 2019 auction of renewable energy contracts, dominated by foreign private investment, was cancelled. Natural gas contracts with private developers were renegotiated. Attempts were made to grant clean energy certificates, awarded to clean energy generators that began operations after August 2014, for legacy state-run hydro plants.
Last month, the government suspended synchronization trials for 28 wind and solar projects and placed indefinite limits on the amount of electricity renewable resources can provide to the grid, measures that affected 4.5 GW of capacity.
The final blow may have come on May 15, when the government announced new regulations that give priority to electricity generated by Mexico’s state-run electricity monopoly, Comisión Federal de Electricidad (CFE). Relying on gas and heavy fuel oil, CFE’s energy costs are as high as $141/MWh. In comparison, renewable energy, without marginal costs, goes for about $20/MWh and has generally been dispatched first.
No wonder, then, that as renewable developer Mannti Cummins put it, a WhatsApp war erupted that afternoon and into the evening. (Because Mexican phone companies charge for texts, many phone users resort to the WhatsApp Messenger tool.)
“I read through [the rules], and it hurt. ‘I can’t believe they’re doing this. I can’t believe they’re doing this,’” Energía Veleta’s Cummins told RTO Insider. “It’s just the weirdest thing I’ve ever seen.
“I’ve been in kind of a daze since then,” he said. “This flips the whole market on its head. It kills renewables. They’ve taken some body blows and punches, but it’s a knockout for renewables.”
The new policy also limits new power generation permits and places additional restrictions on new renewable resources. That places at risk 44 renewable projects, worth about $6.4 billion, scheduled to begin commercial operation this year and next.
Mexico’s energy ministry, Secretaría de Energía (SENER), said the rules were necessary because of a drop in demand caused by coronavirus lockdowns and to preserve the grid’s reliability, safety and continuity. Market participants and observers aren’t buying that and note the rules will allow CFE to burn fuel oil the country’s state-run petroleum company, PEMEX, can’t sell in a world awash with oil.
A May 18 report produced by global law firm Norton Rose Fulbright said, “SENER has eliminated any doubt that power sector policy in Mexico is being driven by the state-owned utility and dominant market player [CFE], rather than by sound and competitive policy principles enshrined in Mexican law.”
That would make a seer of José María Lujambio, former legal counsel at Mexico’s regulatory commission (Comisión Reguladora de Energía, or CRE) and the Austin, Texas-based energy practice leader for Mexican law firm Cacheaux Cavazos & Newton. A couple of years ago, he predicted CFE would enjoy a “privileged position” under AMLO, as López Obrador is more commonly known. (See Changes Add Uncertainty to Mexico’s Power Market.)
“It’s another chapter, perhaps the most shocking, among several specific measures that have put obstacles in place for private participation,” Lujambio said last week.
Duncan Wood, director of the Wilson Center’s Mexico Institute and an internationally respected specialist on North American politics, said no one should have been surprised by the recent announcements. AMLO came into power promising greater state control of the country’s natural resources and cracking down on what he said was private corruption.
“Still, it came as a bit of a shock because it’s such an obvious, blatant aggression against the energy reform of 2013,” Wood said in a WhatsApp message. “What we’re seeing here is an attempt to centralize control of the electric system, to promote CFE as the dominant actor within the electric sector.
“Ultimately, this is all about increasing political power and centralizing control over the economy,” he said. “This is one way of attempting to eliminate competition for CFE, not just in terms of competition for generating electrons but about competition for the supply of electricity to the market. If CFE becomes the only actor that can supply electricity, that gives it an enormous amount of political power.”
“[AMLO’s] actions prove he wants to stick it to private companies,” said Cummins.
‘Huge’ Potential
Ambassadors from the European Union and Canada were quick to respond to the latest measures, sending letters to SENER Minister Norma Rocío Nahle on May 15 that were almost immediately leaked to the Mexican media. European companies Engie, Enel, Iberdrola and Vestas and several Canadian firms dominate Mexico’s renewable market.
“This agreement establishes various actions and strategies [for] operational control, which put at risk the operation and continuity of renewable energy projects of Canadian companies in Mexico,” wrote Graeme Clark, Canada’s ambassador to Mexico.
“Potential investors will be completely freaked out by this move,” Wood said.
Some market participants expect legal injunctions to stop the rules before they are in place. That’s what happened following April’s suspension of market tests for renewable resources. The country’s grid manager backpedaled and began pre-operational testing again.
Wood pointed out that during AMLO’s May 18 mañanera — as his daily morning two-hour press conferences are called — Mexico’s president said he respects the decision of the courts.
“I don’t think this is the end of the story, however,” Wood said.
SENER’s proposal was published in Mexico’s version of the Federal Register on May 15, but not before pushback from the national commission of regulatory improvement (CONAMER), which determines whether new laws have an economic impact. CONAMER called for regulatory impact studies and a 20-day public comment period, saying the new measures would pose compliance costs on companies.
Those requests were to no avail. The commission’s chief resigned the afternoon of May 15. An hour later, Cummins said, the decree was published.
“It’s clearly illegal,” he said. “Not only did they not follow the procedures in making changes to regulations, they pushed it through on this fast track.”
“The planning and reliability of the National Electric System requires rational economic regulation for the accelerated and progressive incorporation of all energies,” SENER said in a statement May 16. “In the case of intermittent energies, they must be incorporated through the intervention and necessary support of plants that have full availability and provide planning and operational reserves.”
As if to rub salt in the wounds, CFE Director Manuel Bartlett said last week private renewable companies should pay for part of the market’s baseload power. “Do you think it’s fair for the CFE to subsidize these companies that don’t produce power all day?” he asked Reuters.
So where does Mexico’s electricity market go now? Wood said that barring an electoral loss in 2022’s “mid-terms” and an ensuing AMLO resignation, private developers will have to wait until the next administration takes over in 2024 for a change in fortunes.
“Mexico has incredible natural endowments for renewable energy,” he said. “It has shown that if you create the right legal framework and regulatory framework, then companies from around the world are willing to invest in renewable energy and produce electricity at an incredible low cost.
“There are huge opportunities for renewable energy long-term,” Wood said. “But short-term, not a lot.”
Stakeholders last week encouraged PJM to take a more active role in facilitating carbon pricing as more states look to join the Regional Greenhouse Gas Initiative (RGGI).
Philips said PJM can support a technical conference without endorsing carbon pricing and help states achieve their environmental goals without having a uniform carbon price.
“PJM’s always been a leader in advocating that markets drive reliability,” Philips said during the Carbon Pricing Senior Task Force’s May 19 meeting, its seventh meeting since its formation last summer. “Now is not the time to abdicate that leadership by not participating in something like this.”
Market Monitor
John Hyatt of Monitoring Analytics recommended PJM “provide a full analysis” of the impact of carbon pricing on generating units and the revenues that would result to allow “states to consider a potential agreement on the development of a multistate framework for carbon pricing and the distribution of carbon revenues.”
The Market Monitor said a $10/metric ton carbon price would increase short run marginal costs by $3.34/MWh (24%) for a new combined cycle plant and $8.63/MWH (31%) for a new coal plant. For 2019, that would have increased LMPs from $27.32/MWh to $30.71/MWh, a 12% rise, based on the impact on the marginal units’ offer prices (not including a counterfactual redispatch of the system).
A $50/ton price would boost combined cycle plants’ costs by $16.72/MWh (122%) and coal plants by $43.15/MWh (156%).
The Monitor said a $10/ton carbon price would generate $3.6 billion annually in carbon allowance revenues in PJM states.
The current patchwork of state policies has resulted in wildly varying renewable energy credit (REC) prices within PJM, with an implied carbon price ranging from $5.63/ton to $19.21/ton in 2019. Solar REC prices last year ranged from an implied price of $50.23/ton to $806.35/ton, the Monitor said.
The Monitor said the varying REC prices are “inconsistent with an efficient market and inconsistent with the least-cost approach to meeting state environmental goals.”
“Using an RGGI model would leave carbon pricing within the control of the states and not of FERC or PJM,” said Monitoring Analytics President Joe Bowring. “States could define the desired carbon price. The carbon price would simply be part of the short-run marginal cost of operating units in PJM and treated like fuel or other emissions costs.”
Vistra Energy
Becky Robinson of Vistra Energy said her company needs a supportive market policy to achieve its emissions goals. Vistra has announced a goal to reduce CO2-equivalent emissions by more than 50% by 2030 and by 80 to 100% by 2050 from 2010 levels.
She said a national, economy-wide price on carbon with dividend payments to help alleviate the rise in energy costs would be the best solution. But she said discussions like the ones happening in the senior task force are a step toward developing a fix.
“We are definitely a believer in the power of economics to change markets and to drive change in the resource mix,” Robinson said.
Disparate state policies regarding clean energy have left states wishing to act on carbon stymied by leakage with the dispatch of cheaper fossil-fuel generated power in non-participating states, she said. FERC rulings that expand the minimum offer price rule (MOPR) to cover state-subsidized generation have also undermined state efforts, causing some states to contemplate exiting PJM’s capacity market. (See NJ Regulators Weighing Input on Capacity Market Exit.)
Vistra wants states to have an in-market clean energy policy option that would not be penalized by MOPR, Robinson said, and is open to sub-regional border adjustments or other market changes empowering state policies.
Robinson said the modeling presented by PJM so far has been “inconclusive” on the best border adjustment method, noting that emissions impacts differ depending on the configuration of participating states. RGGI currently includes New York, the six New England states and three PJM states: Delaware, Maryland and New Jersey. Virginia is also poised to join by the beginning of 2021, and Pennsylvania Gov. Tom Wolf issued an executiveorder in October directing state officials to develop a rulemaking by July 31 for joining the compact. (See Critics: Pa. RGGI Hearing Stacked with Detractors.)
During the May 19 task force meeting, PJM presented an updated study on carbon pricing and potential leakage mitigation mechanisms, expanding on another report issued March 27.
Robinson said the studies show that without border adjustments, carbon pricing works better as the pricing footprint gets bigger.
The reports found that with the Maryland, Delaware and New Jersey footprint in RGGI, carbon pricing alone increases net emissions in PJM while border adjustments decrease net RTO emissions. With RGGI expanded to Virginia and Pennsylvania, carbon pricing alone decreases net RTO emissions, while border adjustments increase net RTO emissions. (See PJM Panel Weighs Impact of Pa., Va. Joining RGGI.)
“If what you care about is emissions, it’s not clear that border adjustments are a good thing or a bad thing,” Robinson said. “It’s very case specific.”
Jason Barker of Exelon asked Robinson what solution Vistra recommended the task force consider, noting the group’s problem statement and issue charge call for examining border adjustments and leakage mitigation.
Robinson said coming up with a “mutually agreeable solution” for all interested stakeholders should be the goal of the task force. For the states that are not interested in carbon pricing, there should be a mechanism for quantifying the incremental value of carbon pricing. The results should be presented to all the states in PJM to determine if the value outweighs the cost.
LS Power
Philips gave a presentation for LS Power, the second largest privately held generation company in the PJM market with more than 11,000 MW of capacity. She said LS Power remains “technology neutral” when it comes to generation — with resources including pumped storage, solar and natural gas combined cycle facilities — and continues to invest where price signals are transparent.
PJM’s competitive market structures have allowed for ongoing investment opportunities that provide consumer benefits, Philips said, and the adoption of transparent carbon pricing within the RTO would continue to provide opportunities for investment and innovation.
“We want the markets to work so we can make investments in a renewable portfolio as well as everything else,” she said.
LS Power has more than 11,000 MW of generation in PJM. | LS Power
Barker asked Philips what LS Power would like to see the task force accomplish.
Philips said she supports requests for more data from PJM on the cost and revenue impact to states and would also back Vistra in considerations about how border adjustments could and could not work.
The open-ended nature of the task force charter allows for broad discussions in search of solutions and could bring more changes if stakeholders actively encouraged input from state commissions and legislators, she said. PJM’s markets have already driven change to policy and will continue to bring innovation.
“What PJM has done already in terms of driving down emissions is remarkable. And they’ve maintained regional reliability while doing it,” Philips said. “Obviously, we wish everybody would embrace a carbon price because that would solve a lot of problems. But recognizing that’s not going to happen at this point, we’d at least like to keep the ball moving and get as much of these externalities into the market and priced appropriately.”
Exelon
Kathleen Robertson, director of strategic initiatives and environmental policy for Exelon, said PJM should immediately begin to develop border adjustments for RGGI, which is anticipated to cover the majority of PJM load by 2022.
Exelon’s modeling assumed all RGGI generators have carbon costs included in their bids. Offers from non-RGGI generators would not include carbon, costs but power flowing from a non-carbon region to a carbon region would be subject to an additional wheeling cost.
Robertson said Exelon’s analysis concluded that well-designed border adjustments preserve efficiencies of regional energy markets and reduce emissions while preserving state policy choices.
Proceedings to conclude the sixth-largest bankruptcy in U.S. history will likely happen via video starting Wednesday, the judge overseeing PG&E Corp.’s Chapter 11 reorganization said last week.
Judge Dennis Montali, with the U.S. Bankruptcy Court in San Francisco, conducted a virtual hearing using Zoom on May 19 in which he spoke from his home with a dozen lawyers in New York, California and elsewhere. The remainder of hearings in the PG&E bankruptcy case will probably also be held via video because of the COVID-19 crisis, he said.
The purpose of the May 19 hearing was to establish the schedule for proceedings to approve or reject PG&E’s $60 billion reorganization plan, including the $13.5 billion it has promised to some 80,000 victims of wildfires sparked by its equipment in recent years.
Fire victims and other creditors, about 250,000 in all, had to cast their ballots on the plan by May 15. A two-thirds vote is required for approval.
Late Friday, Prime Clerk and PG&E filed lengthy documents with the court detailing the voting results. Wildfire victims voted by an 85% majority to approve PG&E’s Chapter 11 plan, and the other creditors overwhelmingly supported it, too.
“Fire victims have spoken, and they have spoken loudly and resoundingly in favor of the plan. The time has come to confirm the plan,” PG&E said in its filing.
Bankruptcy Judge Dennis Montali, top left, and lawyers in the PG&E bankruptcy discuss confirmation proceedings May 19.
Trial Starts Wednesday
The “confirmation” trial of PG&E’s plan is scheduled to start Wednesday. After hearing from attorneys for all major parties, Montali will have to decide whether to approve PG&E’s reorganization proposal.
PG&E is trying to exit bankruptcy by June 30 to meet the requirements of Assembly Bill 1054, a measure pushed through the State Legislature by Gov. Gavin Newsom last July that creates a $21 billion fund to insure utilities against future wildfires. California law holds utilities strictly liable for wildfires sparked by their equipment.
May 15 also was the deadline for parties to file objections to the plan. Dozens did so, including the state and federal governments, the U.S. Trustee in the bankruptcy case, and the city and county of San Francisco. They questioned provisions in the plan that they say could exculpate PG&E, its fiduciaries and associates for actions they take after the bankruptcy case has ended.
The Tort Claimants Committee (TCC), which represents fire victims, objected to the plan based on a lack of assurances that the $6.75 billion in PG&E stock, intended to fund half of the victims’ trust as part of a negotiated settlement agreement, will hold its value amid the coronavirus pandemic and potential wildfires this summer and fall.
“The plan … fails to provide fire victims with the treatment and value that was agreed to in the settlement,” the TCC wrote. “Instead, the plan has whittled away various aspects of the settlement and could harm fire victims in amounts that are in the billions of dollars.”
PG&E lawyers told the judge May 19 that negotiations and mediation are underway that could resolve the objections before Wednesday’s confirmation hearing.
CPUC to Vote Thursday
The California Public Utilities Commission is scheduled to vote on PG&E’s reorganization plan Thursday, wrapping up an investigation that began in September. The vote was delayed a week after a party to the proceeding sent an improper ex parte email, the CPUC said. (See related story, Improper Email Delays CPUC Vote on PG&E Plan.) AB 1054 tasked the commission with ensuring PG&E’s plan is in the public interest, including “the electrical corporation’s resulting governance structure … in light of [its] safety history, criminal probation, recent financial condition and other factors deemed relevant.”
A proposed decision by a CPUC administrative law judge recommended approving the plan as long as PG&E agrees to enhanced oversight and enforcement by the commission. The utility has said it will accept the changes, and it agreed earlier this month to pay a record $1.9 billion in penalties levied by the CPUC. (See CPUC, PG&E Agree to Record $1.9B in Penalties.)
Sentencing Ahead
The utility has said it intends to plead guilty to 84 counts of involuntary manslaughter and one count of starting an illegal fire stemming from the Camp Fire in November 2018. State investigators determined a PG&E transmission tower ignited that blaze, the deadliest and most destructive wildfire in state history, which destroyed much of the town of Paradise.
The Butte County District Attorney has said that PG&E’s sentencing hearing will be held on June 16 and streamed live on the Butte County Superior Court’s YouTube channel.
PG&E remains on criminal probation for six felonies related to the San Bruno gas pipeline explosion in September 2010.
FERC on Thursday largely accepted PJM’s Order 845 compliance filing addressing concerns over a lack of transparency regarding contingent facilities (ER19-1958).
Contingent facilities are unbuilt interconnection facilities and network upgrades upon which an interconnection request’s costs and timing are dependent.
In December, FERC approved six of PJM’s 10 Order 845 proposals, requiring changes on four issues. A Feb. 21 filing by the RTO sought to address the commission’s concerns by clarifying the scope of the study and the criteria used and also clarified that studies for provisional interconnection service will be conducted annually.
Thursday’s order accepted PJM’s filing on three of the four issues that required changes, including: revisions regarding contingent facilities; provisional interconnection service that allows limited operation of a generating facility prior to completion of the full interconnection process; and rules governing technology changes that can be considered without affecting the interconnection customer’s queue position. All three revisions are to go into effect July 20.
FERC’s December order also required PJM to conduct the surplus interconnection service process outside of the interconnection queue. Surplus service is any unused portion of interconnection service established in a large generator interconnection agreement.
PJM’s revisions required that surplus service be only from in-service generators and that use of the service cannot impact the existing system or other queue projects as determined by load flow or short-circuit and stability analyses. Applicants will be required to make a study deposit of $10,000 plus $100/MW, not to exceed $110,000.
The American Wind Energy Association, Solar Energy Industries Association and the Solar Council, filing jointly, challenged PJM’s revisions on the surplus interconnection study, saying that they did not specify whether a surplus interconnection customer will receive a refund for the unused portion of its deposit if an application is rejected or withdrawn.
FERC agreed with the groups’ comment, writing that PJM needed to add language to provide for refunds. It directed PJM to submit a compliance filing within 120 days and make the surplus interconnection service effective Nov. 17.
“We find PJM’s proposed effective date reasonable, given the software and manual changes PJM needs to make before implementing these compliance requirements,” FERC wrote.
Rehearing Denied
FERC also rejected a rehearing request filed Jan. 21 by Leeward Renewable Energy challenging its December order. Leeward argued that FERC had failed to address whether PJM can reject an interconnection customer’s “technological advancement request” as constituting a material modification without any review or analysis.
Leeward cited a proposed Ohio wind project that it wanted to convert to a solar project in response to state legislation that nearly tripled the minimum property line setback for wind turbines. Leeward said PJM judged the change a material modification — forcing the developer to relinquish its queue position and file a new interconnection request without reviewing studies, which the company said is contrary to Order 845 and the RTO’s Tariff.
PJM said the commission in Order 845 stated that “a change between wind and solar technologies involves a change in the electrical characteristics of an interconnection request.”
Site of a proposed Ohio wind farm and solar project brought to PJM by Leeward Renewable Energy in 2017. Leeward cited the project in a FERC filing against PJM. | PJM
Leeward responded that although Order 845 found that a change between wind and solar technologies cannot automatically be considered a permissible technological advancement, such a change should not be automatically considered a material modification and that transmission providers should be required to evaluate such changes.
In denying rehearing, the commission said that interconnection customers seeking to enter the technological change procedure must demonstrate that the proposed change results in “equal to or better” electrical performance. “Should it fail to do so, such a proposed change should proceed through the material modification procedures,” FERC said.
The commission said PJM’s February compliance filing proposed a new procedure for responding to requests to modify interconnection request to include a technological advancement.
“In light of our discussion above, accepting PJM’s new Tariff section 36.2A.2.2 and reminding PJM of its obligation to provide an explanation if it cannot accommodate a proposed technological advancement without triggering the material modification provisions, we find that Leeward’s concerns regarding technological advancement requests raised on rehearing have been addressed and, thus, are moot,” FERC said.
Energy Harbor has agreed to pay Ohio Valley Electric Corp. (OVEC) $32.5 million and drop its attempt to abrogate a 30-year power purchase agreement signed by its predecessor, bankrupt FirstEnergy Solutions (FES).
In a settlement lodged with FERC on May 19, the companies said Energy Harbor will assume FES’ obligations under the multiparty intercompany power agreement (ICPA) as of June 1 and pay OVEC $32.5 million “for any cure costs associated with such assumption.”
OVEC agreed to waive all claims against FES and Energy Harbor arising prior to June 1 and withdraw a complaint it filed with FERC before FES’ bankruptcy and its appeal of the bankruptcy court order confirming FES’ reorganization.
Under the ICPA, which runs through June 30, 2040, OVEC provides power from its two coal-fired generating plants — the 1.1-GW Kyger Creek in Cheshire, Ohio, and 1.3-GW Clifty Creek in Madison, Ind. — to Energy Harbor and seven other corporate “sponsors.” FES signed the ICPA in 2010, taking a 4.85% “power participation ratio,” which required it to pay about $30 million annually to cover OVEC’s losses.
Ohio Valley Electric Corp.’s Kyger Creek Power Plant, a 1.08-GW coal-fired generator south of Cheshire, Ohio
Bankruptcy Filing
OVEC filed a complaint on March 26, 2018, asking FERC to rule that allowing FES to reject the ICPA under the Bankruptcy Code without first obtaining commission approval violated the Federal Power Act. FES filed its Chapter 11 bankruptcy petition five days later.
In October 2018, OVEC filed a proof of claim seeking $531 million for damages from FES’ rejection of the contract. OVEC also sought $29.3 million for power it provided to FES while the company was in bankruptcy.
FES changed its name to Energy Harbor upon emerging from bankruptcy in February, with former bondholders owning 50% of the equity. In March, FERC ordered a paper hearing to consider FES’ attempt to void the OVEC contract and PPAs with renewable generators as part of its bankruptcy proceeding (EL20-35). (See FERC Sets Hearing on FirstEnergy PPAs.)
The commission acted after the 6th U.S. Circuit Court of Appeals issued a mandate overruling a U.S. bankruptcy court’s May 2018 injunction preventing FERC from issuing any order requiring FES to continue complying with the contracts. The appellate court also reversed the bankruptcy court’s ruling allowing FES to reject the contracts.
On May 19, the commission granted OVEC and Energy Harbor’s request to extend the briefing schedule in the case for 30 days to “allow OVEC to avoid incurring the time and expense of preparing a reply brief that they state is likely to be unnecessary due to” the settlement.
Litigation Costs, Time
OVEC and Energy Harbor said they called a truce to end litigation that could have continued for years and cost millions.
“The parties’ disputes have involved complicated legal and factual issues, with appeals now having made their way to the United States Court of Appeals for the Sixth Circuit multiple times,” they said. “There is no doubt that the litigation between FES and OVEC has been hard-fought, complex, time-consuming and costly.”
The companies also said the settlement will ensure bigger recoveries for FES’ creditors. “Creditors of FES will no longer be diluted by OVEC’s asserted claim, which, assuming the estimated recoveries in the disclosure statement, would have been entitled to receive cash distributions of over $160 million if allowed in full.”
The Bankruptcy Court for the Northern District of Ohio will hold a hearing June 16 to consider the settlement.
Looking Forward
Newly emerged from bankruptcy, Energy Harbor is using its cash flow and low debt to attract investors. | Energy Harbor
The deal also will allow Energy Harbor’s management “to focus on the growth and success of the reorganized business,” the companies said. OVEC will waive its claims against FES, including its rejection damages claim of $531 million.
Energy Harbor and OVEC pledged to work together “to reallocate to EH the right to offer its ‘power participation ratio’ share of OVEC’s ‘available energy’ … through the offering of energy and capacity” in PJM.
Energy Harbor said that while it continues “to believe that the costs associated with the ICPA are burdensome to their retail business, [Energy Harbor] understand[s] that OVEC is focused on improving its operational cost structure and that recent Ohio state legislation will assist OVEC in maintaining financial stability while doing so.”
Ohio House Bill 6 authorized a surcharge on electricity customers to subsidize OVEC’s coal plants in Ohio and Indiana and FES’ — now Energy Harbor’s — Davis-Besse and Perry nuclear plants.
“The reorganized debtors believe that operational improvements and cost savings can be achieved through their ongoing participation in OVEC pursuant to the ICPA, and they are ready, willing and able to assist in those efforts.”
Pitch to Investors: Nuclear Power and Retail
Energy Harbor emerged from bankruptcy with low debt and largely subsidized generation, winning it investment-grade ratings from Moody’s Analytics and Standard and Poor’s.
In March, the first month after emerging from bankruptcy, the company reported $142 million in revenue and a $124 million net loss, driven largely by $153 million in losses on nuclear decommissioning trust investments. It also repurchased $113 million in company stock, part of a plan to purchase up to $800 million in shares over nine months. Its adjusted cash flow for the month, including its nuclear fuel amortization expense, was $23 million.
Energy Harbor is retiring 669 MW of coal-fired generation at the W.H. Sammis plant at the end of this month but rescinded plans to shutter Units 5-7 (1,491 MW) after winning subsidies from the Ohio legislature. | FirstEnergy Solutions
An investor slide deck posted May 10 touts the company’s carbon-free nuclear generation and its retail sales operation, which it says will generate $200 million in annual cash flow by 2022, when it says more than 95% of its free cash flow will come from carbon-free sources.
Energy Harbor owns about 7,200 MW of capacity, including three nuclear plants: Beaver Valley Power Station in Shippingport, Pa. (1,872 MW); Davis-Besse Nuclear Power Station in Oak Harbor, Ohio (908 MW); and Perry Nuclear Power Plant in Perry, Ohio (1,268 MW). The company rescinded plans to retire Beaver Valley in March, citing Pennsylvania’s efforts to join the Regional Greenhouse Gas Initiative. (See Beaver Valley Nuclear Plant to Stay Open.)
The company is retiring the coal-fired Units 1-4 of its W.H. Sammis Plant (669 MW) in Stratton, Ohio, at the end of this month, with a 13-MW diesel unit set to shut down next year. It had also planned to shutter Sammis’ coal-fired Units 5-7 (1,491 MW) in 2022, but FES rescinded the notice last year in response to Ohio House Bill 6. Its coal-fired Pleasants Power Station (1,278 MW) in Willow Island, W.Va., is set to retire in June 2022.
Energy Harbor rescinded plans to retire the Beaver Valley nuclear plant in March, citing Pennsylvania’s efforts to join the Regional Greenhouse Gas Initiative.
Three-quarters of its cash flow comes from nuclear zero-emission credits, plus capacity payments and retail sales, leaving only 25% “commodity exposed,” it says.
It notes its gross debt-to-cash-flow ratio is only 0.8, less than a third of the “peer average” of 2.9.
Another selling point: The “company [is] not expected to be a material federal cash taxpayer for [the] foreseeable future.”
SPP staff and stakeholders on Friday lauded retired CEO Nick Brown for his leadership in building the RTO from a small regional organization into one that now reaches from the Texas Panhandle to the Dakotas.
Given the new normal, the celebration was a virtual one. Brown, sporting his usual SPP-logoed shirt, sat at home next to his wife, Susan, and watched as former and current staffers, directors, regulators and industry insiders praised him for the RTO’s success during his tenure.
Brown announced his retirement last July after 35 years with the grid operator, including 16 as CEO. (See SPP’s Brown to Retire as CEO in 2020.)
Nick, with his wife, Susan, responds to stakeholders during his virtual retirement celebration.
American Electric Power CEO Nick Akins invited Brown to Columbus, Ohio, for a game of golf and to share his expertise. The two were classmates at Louisiana Tech (Class of ’82), where they went by Nick A. and Nick B. to avoid confusion, and began working at Southwestern Electric Power Co. on the same day.
“He will leave a lasting legacy for SPP and the industry,” Akins said.
Former FERC Commissioner Colette Honorable, who also chaired the Arkansas Public Service Commission, toasted Brown with a glass of New Mexico bubbly and thanked him for exhibiting a collaborative approach with stakeholders, rather than “fighting everything at FERC.”
Omaha Public Power District’s Joe Lang recalled his first stakeholder meeting. Brown, as he always does during opening introductions, referred to himself as, “Nick Brown, SPP staff.”
“That’s when it hit me that SPP’s inclusive culture is driven from the top,” Lang said.
Harry Skilton, an SPP director for 18 years, welcomed the ex-CEO to the RTO’s alumni club.
“We’re a small group. There’s no dues or initiation ceremony,” Skilton said. “The only thing I ask of you is that anytime any of us should meet, to raise a good glass of claret to SPP and its motto, ‘Keep the lights on.’”
Nick Brown with his gift from the SPP board, a bronze sculpture | SPP
CEO Barbara Sugg credited her predecessor with inspiring her to reach beyond herself when she joined SPP. Sugg was appointed to replace Brown in January. (See SPP Board Taps Barbara Sugg as New CEO.)
“He believed in me. He saw things in me I didn’t see in myself,” she said. “He always set really high expectations and challenged us to meet those expectations. You can’t make people follow you. They follow you because you inspire them. I’m proud, I’m humbled, and I’m overwhelmed, in this crazy pandemic, to be stepping into his footsteps.”
Sugg assured those watching and listening that she will continue to “foster all those great things” Brown put in place.
“Nick poured his heart and soul and the vast majority of his life into SPP,” she said.
Brown’s retirement was effective in April. SPP had planned a dinner and celebration in his honor that month, but the coronavirus pandemic waylaid those plans.
Board of Directors Chair Larry Altenbaumer said, “It made sense to go forward at this time and conduct the event sooner, rather than later, in the same manner in which many of us are conducting our daily lives.”
Nick Brown (left) confers with SPP colleagues Claudia Milam and Frank Royster in 1995. | SPP
When it came his time to speak into his wireless device, Brown recalled that when he joined SPP in 1985, SWEPCO CEO John Turk asked him whether he was sure what he was doing. After all, the organization only had five employees at the time, and Brown had already established himself as a gregarious, outgoing person.
“How are you going to be who you are when you love being around people so much?”
Brown, noting that SPP had about 300 stakeholders already, said he would do just fine.
“It’s just been a tremendous ride,” Brown said. “I’ve really kind of enjoyed having all of these weeks, from the official retirement day until today, spending time, thinking of each and every person who has touched me in this industry. We’ve shared blood, sweat and tears. This has been an exciting experience, that’s for sure, but things change and things move on.
Brown led the organization as it was recognized by FERC as an RTO and expanded into 14 states, admitting Nebraska utilities in 2009 and the Integrated System in 2015. SPP added a balancing market in 2007 and a wholesale day-ahead market in 2014, while also investing nearly $10 billion in transmission facilities. It became a reliability coordinator in the Western Interconnection in 2019 and will also manage an energy imbalance service market with eight western participants next year.
SPP’s membership will reach 100 members when EDF Renewables joins on June 1. The grid operator already has almost 24 GW of installed capacity and has produced as much as 78% of its energy from renewable sources.
The Board of Directors and Members Committee presented Brown with a resolution of “deep gratitude” recognizing his “unparalleled leadership.” Earlier in the day, they delivered to his house a bronze sculpture, titled “Place of Honor,” by his and Susan’s favorite artist, Colorado sculptor Joshua Tobey.
“I couldn’t be more pleased with the position the organization is in,” Brown said. “With the board and the management team, and with Barbara as the new CEO, the future is great. I’m really excited to watch the organization continue to prosper,” Brown said. “Thank you. Thank you. Thank you, very much.”
FERC last week rejected requests to change PJM’s capacity market rules to accommodate seasonal resources, saying the complainants failed to prove current market rules are unjust and unreasonable (EL17-32, EL17-36).
The order was prompted by a December 2016 complaint by Old Dominion Electric Cooperative (ODEC), Direct Energy Business and American Municipal Power and a January 2017 filing by Advanced Energy Management Alliance (AEMA) over the procurement of capacity in PJM’s Reliability Pricing Model.
ODEC asked the commission to establish a proceeding to allow seasonal resources to participate in capacity auctions. AEMA said PJM’s move to 100% Capacity Performance resources was unnecessarily costly for ratepayers, citing studies that it said proved that all of PJM’s resource adequacy risk is in the summer.
PJM adopted the CP rules — which increased bonuses for overperformance and penalties for underperformance — in response to the 2014 polar vortex, when the RTO came close to shedding load with as much as 22% of its generating fleet on forced outages.
“The core of the complaints is that because PJM is a summer-peaking system, PJM could acquire more summer capacity than winter capacity at an economic savings without sacrificing system reliability,” the commission said. The complainants pointed to PJM data that they said showed that by increasing summer requirements by about 500 MW, the RTO could replace more than 17,000 MW of annual capacity with less expensive summer resources without jeopardizing reliability.
Reasonable Accommodation
The commission ruled in 2015 that using the same capacity requirement for winter and summer was justified by deteriorating resource performance and the change in the RTO’s resource mix. Allowing non-year-round resources to continue participating in the capacity market could lead to reliability problems in non-summer months when seasonal resources are unavailable, it said. The commission said PJM had provided a reasonable accommodation by allowing storage resources, intermittent generators, demand response and energy efficiency to submit aggregated offers.
The commission’s approval of CP was backed by the D.C. Circuit Court of Appeals, which ruled that the “law provides no basis to claim the commission cannot approve uniform performance requirements simply because those requirements will be easier to satisfy for some generators than others.”
In response to the commission and D.C. Circuit rulings, the complainants provided planning studies and other evidence that they said proved that PJM could meet its resource adequacy targets more cost-effectively by tailoring its procurements to recognize seasonal variation. Summer peaks can top 150 GW, while the winter typically peaks at less than 100 GW.
Although the commission held a technical conference in April 2018 to explore the issues raised by the complaints, it said there was insufficient evidence to overturn the CP rules.
PJM’s summer peaks can top 150 GW, while the winter typically peaks at less than 100 GW. | PJM
Data Limitations
FERC cited PJM’s warning that “modeling assumptions underlying the data on which complainants rely … warrant caution in interpreting the meaning of that data.”
While the RTO’s annual installed reserve margin study indicates that only a small amount of loss-of-load-expectation risk occurs in the winter, “recent operating experience suggests that such risk may in fact be higher,” FERC said.
PJM also said AEMA’s contention that an additional unit of summer-only capacity has 97% of the reliability value of an additional unit of year-round capacity was based on an incorrect premise that changing to seasonal capacity resources would not also change other modeling assumptions underlying the data.
“In light of these identified limitations in the data presented, we are not persuaded that the evidence complainants present is sufficient to show that the Capacity Performance model is no longer just and reasonable,” the commission said. “Ultimately, we are not convinced that it is necessary for PJM to abandon its single-product Capacity Performance model based upon the limited experience since the commission’s approval. As PJM argues, it deserves the opportunity to gain more experience with implementation of Capacity Performance and its rules over time to determine whether it provides performance and reliability during all seasons of the year.”
Glick Concurrence
Although the ruling was unanimous, Commissioner Richard Glick wrote a concurrence saying that “a seasonal capacity construct appears to be a more just and reasonable approach than PJM’s current one-size-fits-all” rules.
Glick said that while he agreed the complainants had not proved that the CP rules are unjust and unreasonable, “the record does, however, hint at a number of more fundamental problems with PJM’s capacity construct [that] merit a comprehensive review in PJM’s stakeholder process and, if necessary, by this commission.”
He said the evidence “underscores the difference between the reliability challenges in the summer and winter and … suggests that moving away from a uniform annual product could allow more resources to provide capacity, thereby increasing competition and promoting more efficient pricing.”
“Although the high reserve margins that help manage the summer-time peaks may also address winter concerns, they are not the most direct way to do so,” he continued. “The fact that having extra resources on the system may help manage non-peak reliability challenges does not necessarily justify PJM’s current approach or excuse it from pursuing means of addressing those challenges more directly and cost-effectively.”
Glick also pointed to the “unintended consequences” of PJM’s excess capacity.
“PJM, its stakeholders and this commission have devoted considerable time and resources to promoting proper price formation in PJM’s energy and ancillary service markets. Over-procuring capacity tends to dull those price signals, reducing, or altogether eliminating, many of the benefits of those price formation efforts.”
He also said he was troubled by “the implication of PJM’s statement that adopting a seasonal market could cause ‘premature resource retirement.’”
“PJM’s goal cannot be the protection of ‘conventional’ resources, nor should it spend its time fretting over the effects that a more efficient market design may have on the resource mix,” Glick said. “Instead, PJM should be focused on identifying the services the grid needs to remain reliable and structuring its markets to procure those services in the most efficient, technology-neutral manner possible. In any case, it is hardly ‘premature’ for a resource to retire because some other resource can more efficiently meet the needs of the market. That type of competition should be the goal of the capacity market, not a problem to be avoided.”
Glick also said excess capacity also has undermined the “underpinnings of PJM’s Capacity Performance proposal, which envisioned many penalty hours per year.”
“The commission’s recent decisions regarding PJM’s variable resource requirement curve and minimum offer price rule (MOPR) will only exacerbate that capacity glut, further reducing the chances of a Capacity Performance penalty. …
“Capacity Performance events will be even less likely after the issuance of today’s order on the operating reserve demand curve, which will result in PJM carrying reserves far in excess of its reserve requirement, further reducing the likelihood of a Capacity Performance event.” (See related story, FERC Approves PJM Reserve Market Overhaul.)
“If there is little-to-no prospect of a capacity shortfall, then it would seem correspondingly harder to justify the qualification restrictions, including the limitations on seasonal resources. I recognize that some of the capacity glut is the result of the commission’s actions, not PJM’s, and that this share may continue to grow as the consequences of the commission’s MOPR ruling play out. But that should not stop PJM from taking a hard look at whether Capacity Performance remains appropriate under current market conditions and, in particular, whether the barriers it created for seasonal resources should be removed.”
PJM’s rules for pseudo-tied resources lack “sufficient notice and transparency” regarding how the RTO conducts its market-to-market (M2M) flowgate test and applies its electrical distance requirement, FERC ruled last week.
Acting on complaints by Brookfield Energy Marketing and Cube Yadkin Generation, the commission ordered PJM to amend its Tariff within 45 days to address the shortcomings.
Brookfield contended that PJM’s deliverability requirements and M2M flowgate test were interfering with the ability of the company’s Calderwood and Cheoah hydroelectric generation facilities in the Tennessee Valley Authority and Duke Energy balancing authority areas to provide capacity in the RTO. The commission ruled that Brookfield had not proven that PJM’s pseudo-tie requirements are unjust and unreasonable (EL19-34).
The commission also rejected Cube’s allegation that PJM applied the electrical distance requirement in an unjust and unreasonable manner to the company’s four hydroelectric resources. But the commission required the RTO to amend its Tariff to spell out the procedure in more detail (EL19-51). The Tariff defines “electrical distance” as “the measure of distance, based on impedance and in accordance with the PJM manuals, from the generation capacity resource to the PJM region.”
Brookfield Energy Marketing’s Calderwood Dam is on the Little Tennessee River in Blount County, Tenn.
FERC ordered PJM to revise its Tariff to provide pseudo-tie applicants with results of their tests and related work papers and to post on its website the assumptions used in the tests. It also required the RTO to meet with applicants if requested to discuss assumptions, modeling and test results.
In a third order, FERC rejected a complaint by Tilton Energy alleging that PJM wrongly determined that Tilton’s pseudo-tie from the MISO BAA into PJM did not pass the M2M flowgate test (EL18-145).
The company filed a complaint after its 176-MW natural gas-fired generation facility in the MISO BAA was rejected by PJM because 44 of the tested flowgates failed the test. PJM uses the test to determine whether it can use a dispatchable internal resource to alleviate the impact on congestion caused by the external pseudo-tied resource.
The failed test prevented Tilton from participating in capacity auctions after the 2021/22 delivery year, despite having served as a capacity resource in two prior years.
The commission sided with PJM’s interpretation of its Tariff regarding the testing. “We find that PJM’s interpretation reasonably permits PJM to reject pseudo-ties that could create new coordination and congestion costs,” it said.
It said the fact that Tilton had previously been accepted as a capacity resource was irrelevant. “Tilton has not previously been subject to the flowgate test, given the five-year transition period for existing pseudo-tied resources,” it said.
