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April 17, 2025

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PG&E’s Troubles Mount After Camp Fire

By Hudson Sangree

The future of Pacific Gas and Electric is in doubt as the new year begins.

Two months after the Camp Fire — the deadliest wildfire in California history — flared Nov. 8, the utility is facing intense scrutiny from state lawmakers, regulators and a federal judge who is overseeing its probation for the 2010 San Bruno gas line explosion.

Lawsuits have proliferated, blaming PG&E for the Camp Fire, and the company is facing billions of dollars in damages for that blaze and the devastating wine country fires of October 2017.

President Trump and California Gov. Jerry Brown toured the scene of the Camp Fire on Saturday, Nov. 17. Trump called it “total devastation.” | California Governor’s Office

PG&E’s stock price has plummeted by half since the Camp Fire and by two-thirds since the wine country fires, fueling speculation about its solvency. (See Destructive Fire Drives Down PG&E Stock.)

And in recent weeks, state authorities, including the California Public Utilities Commission, have publicly questioned whether the company should be broken up or have its leadership replaced. (See Camp Fire Prompts Talk of PG&E Bailout of Breakup.)

State Sen. Bill Dodd, a Napa Valley Democrat and one of the authors of a 2018 law, SB 901, that allowed PG&E and other utilities to issue long-term bonds to pay for wildfire liability, said the company needs a major shake-up, starting at the top. Dodd said he was reacting to a Dec. 14 CPUC report that alleged PG&E had falsified safety records for underground gas lines.

“PG&E has demonstrated a pattern of poor management and illegal conduct that has shattered lives across California,” Dodd said in a December statement. “This latest revelation underscores the need for systematic change, which must include change on the board of directors and in the executive suite.”

The senator told RTO Insider Friday that he wouldn’t rule out breaking up PG&E into separate gas and electric divisions. “Everything should be on the table,” he said.

On Friday, NPR reported that even PG&E is considering selling off its gas business to cope with staggering wildfire costs. The report relied on unnamed sources. The utility told NPR it was “reviewing structural options” but did not specifically address the sale of any assets.

PG&E said in a news release Friday that it is engaged in a “board refreshment process” and seeking to recruit new board members with expertise in safety. The utility also said it has “formed a special Board committee that is engaging independent experts to advise on best practices in wildfire safety.” The moves respond to criticism from lawmakers and regulators who have said PG&E needs new leaders to help it cure a flawed safety culture that precipitated two years of catastrophic wildfires.

November’s Camp Fire killed 86 residents in Butte County, destroyed nearly 14,000 homes and leveled the town of Paradise, Calif., population 27,000, in a matter of hours. It followed the wine country fires of 2017, for which PG&E has been partially blamed by state fire investigators, as well as the massive gas explosion in San Bruno, Calif., that killed eight and led to PG&E’s conviction on felony charges. PG&E’s problems continued over the holidays, when Judge William Alsup, with the federal district court in San Francisco, asked the state attorney general’s office to advise him on “the extent to which, if at all, the reckless operation or maintenance of PG&E power lines would constitute a crime under California law.”

The AG responded three days after Christmas with a rundown of the charges PG&E could potentially face, ranging from misdemeanors to murder, should it be deemed to have acted recklessly.

Alsup also required PG&E to provide a thorough account of its role in the Camp Fire and the wine country fires of October 2017. PG&E answered with a detailed description of the problems it experienced with its transmission and distribution lines near the Camp Fire’s point of origin on the morning the fire started and said multiple employees had seen the fire start. (See PG&E Grapples with Line Safety After Camp Fire.)

On Thursday, the judge ordered PG&E to submit more information concerning the Atlas Fire, one of 21 major fires that started Oct. 8, 2017, and burned through large swaths of Napa, Sonoma and neighboring counties. The wine country fires killed 44 people and leveled the northern portion of the city of Santa Rosa, Calif. (The case is No. 3:14-cr—00175-WHA in the U.S. District Court for the Northern District of California.)

“PG&E’s most important responsibility is the safety of the customers and communities we serve,” the utility told RTO Insider in an email Friday. “The cause of the Camp Fire is still under investigation. We are aware of lawsuits regarding the Camp Fire. Our focus continues to be on assessing infrastructure to further enhance safety and helping our customers recover and rebuild.”

Here’s a rundown of where PG&E stands at the start of 2019.

The Tubbs Fire in California’s wine country wiped out the Coffey Park neighborhood of Santa Rosa. | California National Guard

Criminal Charges

Pacific Gas and Electric is no stranger to criminal charges in cases involving its equipment.

In June 1997, jurors in Nevada County, Calif., found the company guilty of 739 counts of criminal negligence for failing to trim trees near its power lines and sparking the Trauner Fire, which destroyed 12 homes and burned a historic schoolhouse near the Sierra foothills town of Rough and Ready in 1994.

In the San Bruno case, jurors found the company guilty in August 2016 of five felony counts of knowingly violating federal safety regulations by failing to inspect and test its pipelines and one count of obstructing a National Transportation Safety Board proceeding.

In January 2017, U.S. District Court Judge Thelton Henderson slapped the company with the maximum $3 million fine and ordered it to serve five years of probation, saying PG&E’s crimes posed “a great risk to the public safety.” (That was on top of $1.6 billion in fines levied by the state.) The company was placed under a federal monitor.

The probation from the San Bruno sentence is the basis for Alsup’s current inquiries, which began just after Thanksgiving. Under its terms, PG&E must not commit any federal, state or local crimes. Doing so could subject the company to further penalties, and its probation could be revoked, federal prosecutors told Alsup.

There is already some evidence that criminal charges are possible.

A section of the 30-foot gas pipeline owned by PG&E that exploded in 2010, killing eight people in San Bruno, Calif.

Investigators with the California Department of Forestry and Fire Protection (Cal Fire) have said PG&E equipment was to blame for at least 17 of the wine country fires. Cal Fire forwarded 12 of those cases to county prosecutors, who retain discretion about whether to charge PG&E. So far, no charges have been filed.

The AG’s office said in its brief that it wasn’t making any factual findings on whether PG&E committed crimes.

“Determining PG&E’s potential criminal liability, if any, for recent wildfires would require an investigation into the cause or causes of those fires,” the attorney general’s brief said. “If PG&E caused any of the fires, the investigation would have to expand into PG&E’s operations, maintenance and safety practices to determine whether criminal states were violated with the requisite mental intent.”

That mental intent would be measured on a sliding scale from mere negligence to reckless behavior that could constitute manslaughter or implied-malice murder, it said.

Lawsuits

Multiple lawsuits — about a half-dozen, according to various news reports — have already been filed against PG&E by survivors and insurance companies for what could add up to $15 billion in damages for the Camp Fire, according to one Citigroup estimate. That comes on top of another $15 billion in damages for many of the wine country fires, Citigroup said.

Allstate, State Farm and USAA filed suits last month in state court in Sacramento over billions of dollars in claims they expect to pay from the Camp Fire, The Sacramento Bee reported Thursday.

In another suit, filed by a prominent San Francisco plaintiffs’ firm, Lieff Cabraser Heimann & Bernstein, two children of Ernie Foss, a disabled man killed while trying to escape the Camp Fire, claim the blaze was started by “unsafe electrical infrastructure owned, operated and (improperly) maintained by PG&E Corporation and Pacific Gas & Electric Company.”

“The catastrophic damage and loss of life was preventable,” the lawsuit alleges. “PG&E’s failing infrastructure and its inadequate efforts to maintain its equipment and mitigate risk have caused tragedy before, and PG&E has been sanctioned a number of times for virtually identical misconduct.”

The complaint cites other instances in which PG&E was fined or held criminally liable for deadly fires and explosions, including the Trauner Fire, the San Bruno explosion and a fatal gas explosion near Sacramento in 2008.

“PG&E’s corporate policy of putting profits over public safety has resulted in catastrophic loss of life and injury to persons and property, including the tragic and unnecessary death of Ernie Foss,” the suit contends.

The Lieff Cabraser suit is likely just the start; other law firms have been busy signing up clients in Butte County.

The wine country suits, also called the North Bay California Fire Cases, have been consolidated under a single judge in San Francisco Superior Court and are slowly working their way toward a trial or settlement. The same will likely happen with the Camp Fire claims.

Regulators and Lawmakers

In early December, CPUC President Michael Picker said state regulators would expand their investigation of PG&E’s safety practices after the Camp Fire. (See CPUC Expands Probe Into PG&E Practices After Deadly Fire.) The investigation began in the wake of the San Bruno explosion.

On Dec. 21 the commission released a scoping memo and ruling regarding the investigation that asked whether the company’s management should be replaced, whether members of its board of directors should resign, and whether the company should be broken up into separate gas and electric divisions.

“PG&E has had serious safety problems with both its gas and electric operations for many years,” it said, citing a long list of disasters and problems for which PG&E had been penalized.

“The future of PG&E may also be impacted by other actors beyond the Commission,” the CPUC noted. “The Legislature, the court appointed Federal Monitor, the various courts considering claims against PG&E, the Federal Energy Regulatory Commission, and the communities served by PG&E all have a role in determining PG&E’s future.”

With the state Legislature returning Monday (Jan. 7), lawmakers will have to determine if legislation is needed to help keep PG&E solvent — for instance, by extending the bond provisions of SB 901 to 2018 fires — or whether the company should be reconfigured after a series of catastrophes that has grown unacceptable, even to many centrist lawmakers. (See California Wildfire Bill Goes to Governor.)

Dodd, for one, said it will be hard for PG&E to make amends, regardless of its legal compliance and restitution to fire victims.

“It’s too little, too late,” the senator said. With so much frustration and anger built up against PG&E, it may be time for the utility to face more serious consequences.

“I’m not sure there’s anything they can do,” he said.

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Trade Group Lodges Complaint over MISO Capacity Rules

By Amanda Durish Cook

A group representing MISO power producers filed a complaint with FERC on Monday alleging that the RTO is improperly accounting for the deliverability of some capacity resources, driving down payments to those demonstrably positioned to deliver on their obligations.

The Coalition of Midwest Power Producers (COMPP) urged FERC to force MISO to properly account for deliverability of capacity resources before the annual capacity auction in April in order to safeguard reliability (EL19-28).

MISO control room | MISO

COMPP said MISO’s loss-of-load expectation (LOLE) study process is flawed because it assumes that all capacity resources are fully deliverable on an installed capacity (ICAP) basis. However, the group argued, MISO’s megawatt count from deliverable resources comes up short annually because the RTO allows certain resources to demonstrate deliverability only up to the unforced capacity (UCAP) level.

MISO’s Tariff requires capacity resources to demonstrate either network resource interconnection service (NRIS) or energy resource interconnection service (ERIS) coupled with firm transmission service up to each resource’s ICAP level. While the RTO already requires that all resources be deliverable to load to qualify as capacity resources, its deliverability requirements stipulate that ERIS resources must only secure firm transmission for their UCAP values, which tend to be about 5 to 10% below full ICAP levels.

The discrepancy amounts to a Tariff violation and risks MISO’s adherence to its own planning reserve margin, COMPP said.

“By failing to ensure deliverability on an ICAP basis for all capacity resources, MISO is acting contrary to the assumptions of its LOLE study and failing to procure enough fully deliverable resources needed to meet its [planning reserve margin] as its Tariff requires,” COMPP said.

“The seriousness of this issue is evident in the historically low reserve margins that MISO is experiencing,” COMPP said. “Requiring compliance with the Tariff for the upcoming [Planning Resource Auction] is essential both to maintaining reliability and to ensuring rates are just and reasonable and not unduly discriminatory. Yet, despite the gravity of the situation, the RTO is proceeding in a manner that will continue to improperly count approximately 1,400 MW of undeliverable generation toward satisfying its reliability requirement.”

MISO’s Independent Market Monitor last year also advised the RTO to require a planning resource’s ICAP be deliverable over the network regardless of which interconnection service it uses. (See MISO Concurs with Monitor Ideas, Pledges More Study.) The Monitor found it problematic that MISO’s LOLE study assumes all ICAP megawatts are deliverable when they’re not.

It later pointed out that during past PRAs, as much as 1,400 MW in capacity may not have been capable of delivering to load. At the time, MISO said it would work on rule changes in time for the 2020/21 PRA.

For COMPP, those changes won’t come soon enough. The group pointed out the problem is poised to recur in the upcoming 2019/20 PRA “despite the IMM having recommended that MISO fix it for the past two auctions.” It also maintains that swings even smaller than 1,400 MW “can lead to material differences in the clearing price that fails to send accurate price signals for entry and exit.”

COMPP said that despite MISO’s apparent agreement with the Monitor, it contended that the RTO has designated the issue a low priority by “only targeting to correct its failure” for the 2020/21 PRA.

“Leaving this problem unaddressed for another day fails to abide with [Federal Power Act Section] 206’s requirements and should be deemed unacceptable by the commission. … The lack of urgency on this issue is particularly galling given MISO’s focus on dealing with current reliability issues that have resulted in some 19 emergency actions since the start of the 2016/2017 planning year,” COMPP said.

The organization also requested fast-track treatment from FERC.

MISO said it was in the process of reviewing the complaint.

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CPS Energy Shutters Deely Coal-fired Units

By Tom Kleckner

ERCOT enters 2019 with a major coal plant going into mothballs and two aging gas units set for decommissioning.

After burning the last load of coal at its J.T. Deely plant on New Year’s Eve, San Antonio utility CPS Energy is now in the process of mothballing the two units, which date back to 1977 and 1978.

CPS Energy’s J.T. Deely plant | CPS Energy

The municipal utility in 2011 said it would retire Deely by the end of 2018, 15 years ahead of schedule, thus avoiding millions in environmental retrofit costs. It notified ERCOT of its plans to mothball the plant in 2013, but it must submit a notification of change of generation resource designation (NCGRD) before officially retiring and decommissioning the units.

CPS spokesperson Trace Levos said the utility plans to begin razing the plant in 2025, but utility officials are also pondering converting Deely into a gas-fired plant.

ERCOT spokesperson Leslie Sopko said the grid operator will not have to conduct another reliability-must-run study whenever CPS is ready to retire the units, as the ISO already considers the units to be unavailable.

Deely’s two coal units have a combined capacity of 871 MW. Along with Luminant’s shuttering of three coals plants in late 2017, ERCOT will have seen slightly more than 5 GW of coal-fired capacity shut down over a year. (See ERCOT OKs Luminant Coal Retirements.)

The Texas grid operator survived record-breaking demand last summer without resorting to emergency measures. It is expected to enter this summer with a historically low reserve margin of 8.1%, almost three points lower than last year. (See ERCOT Faces Tight Summer Margins, Market Changes.)

Meanwhile, NRG Texas on Dec. 28 submitted an NCGRD to ERCOT, saying it intends to decommission and permanently retire two previously mothballed gas units at its SR Bertron plant near Houston, effective Jan. 23.

The Eisenhower-era units each have a capacity of 230 MW. They were shut down for economic reasons in 2011.

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ROE Changes Spark Concerns for MISO, PJM Regulators

By Amanda Durish Cook

State utility regulators in MISO and PJM have voiced concerns that FERC’s proposed changes to transmission rate-setting could drive up costs while hampering development of more efficient non-transmission alternatives.

| MISO

In separate letters last month, the Organization of MISO States and the Organization of PJM States Inc. urged the commission to examine whether current return on equity incentives on top of a new base ROE will result in excessive customer costs.

FERC in October signaled it will allow changes to how transmission owners set ROE rates, no longer relying solely on the discounted cash flow (DCF) model it has used for about four decades. Instead, it will rely equally on results from the DCF and three other techniques: the capital asset pricing model, the expected earnings model and the risk premium model. (See FERC Changing ROE Rules; Higher Rates Likely.)

The changes come in response to a D.C. Circuit Court of Appeals 2017 ruling vacating Opinion 531, FERC’s 2014 order on New England TOs’ ROE rates. The new policy would evaluate and incorporate industry-wide risk into ROE estimates — and likely raise rates.

In its Dec. 19 letter, OMS urged the commission to “balance the authorization of sufficient rates of return to encourage the investment on needed transmission against concerns about excessive costs to customers.”

ROE incentives on top of the base ROE should be “targeted and exceptional,” OMS wrote in the letter, signed by board President Ted Thomas, chairman of the Arkansas Public Service Commission.

“Supporters have concerns that at least some incentive adders have become overly generous and do not change or incent the intended behavior on the part of the transmission owners, resulting in excessive costs to customers. Ineffective adders may also be an unintended disincentive to development of non-transmission alternative solutions for reliability and congestion concerns,” OMS said.

Following OMS’s letter, OPSI on Dec. 28 also cautioned the commission that ROE incentives may become too generous under the new ROE. The organization said FERC should be careful to craft ROE incentives that are “truly merited.”

“OPSI has concerns that at least some incentive adders have become overly generous and do not change or incent the intended behavior on the part of the transmission owners, resulting in excessive costs to customers. Such adders may also be an unintended disincentive to development of non-transmission alternative solutions for reliability and congestion concerns,” the organization said.

RTO Adder ‘Questionable’

Both organizations singled out FERC’s 50-basis point adder incentive for RTO participation. OMS said the adder is of “particular concern and warrants scrutiny by FERC,” noting it’s worried the adder “will last in perpetuity.”

“[T]he landscape has changed drastically since 2006 when these adders were first initiated. After more than 15 years of experience with RTOs, the resulting benefits to utility members are now better understood. RTOs are no longer a new policy experiment. Moreover, transmission owners may no longer need an additional incentive adder to simply join an RTO,” OMS said.

OMS also pointed out that FERC over the years has provided other regulatory mechanisms such as formula rates, projected revenue requirements — trued up to reflect under-recovery — abandoned plant and construction work in progress, “all of which reduce transmission owners’ risk.” The group said the mechanisms “should be carefully examined in the context of this and other ROE incentives.”

OPSI called the RTO adder “questionable” since the benefits of RTO participation are now well understood.

OPSI recommended FERC open a notice of inquiry on the ROE issues “for the purpose of examining not only policy around the application of new incentive requests, but also the ability of existing incentives to achieve desired outcomes.”

OMS likewise requested a review of ROE incentive policy “to ensure that customers pay no more than is necessary to develop and to maintain a reliable and efficient transmission grid.”

OMS has previously expressed concern about whether it would be able to contribute its views to the New England ROE docket.

“You have these pretty impactful policy discussions taking place … and it’s not a docket that we are party to,” former OMS Executive Director Tanya Paslawski said during the organization’s Oct. 29 annual meeting.

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FERC OKs PJM Seasonal DR Change Over Monitor’s Protest

By Rich Heidorn Jr.

FERC has approved PJM’s proposal to change how it measures seasonal demand response resources, rejecting a protest by the RTO’s Independent Market Monitor.

PJM currently permits curtailment service providers (CSPs) to combine DR resources within the same transmission zone into a single DR registration, with the capacity value based on the lower of its total summer- or winter-period reduction capability.

Under the changes approved by the commission Dec. 31, resources above 100 kW will be registered individually, with separate summer and winter capacity values (ER19-244).

PJM said the change will give it greater flexibility by allowing dispatch of individual DR resources. It will also aid CSPs, who will no longer have to determine which end-use customers should be aggregated on a DR registration to maximize the nominated value, PJM said.

The change will be effective with delivery year 2019/20, beginning June 1.

Under PJM’s old process (left), customers 3 and 4 would be combined in a single demand response registration with an annual value of 3 MW, the lesser of the combined summer and winter values. Under the new process (right), the two customers would have separate registrations with a combined 3 MW in summer and 4 MW in winter. | PJM

The IMM protested the proposed change, saying that it will overstate the capacity value of DR, displacing other resources, and that allowing more intra-zonal matching will erode locational price signals.

The commission disagreed, saying the changes should result in more accurate DR capacity values.

It also noted that CSPs are already permitted to aggregate end-use customers in a single transmission zone within a registration and satisfy a DR capacity commitment with multiple registrations. “The proposed revisions do not modify either of these permissions, and we find no evidence in the record to suggest that the instant changes will erode locational price signals,” the commission said.

The Monitor also objected to how PJM proposed to estimate load reductions for some resources, saying all should be required to have five-minute interval metering.

The commission said PJM’s use of “flat profiling” for DR that lack five-minute metering can “reasonably reflect” DRs’ performance during emergencies.

“In multiple orders, the commission has declined to require demand resources to upgrade to five-minute metering,” the commission said, adding that such technology is not necessary because of RTOs’ ability to create five-minute load and generation profiles using telemetry and hourly revenue-quality data.

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FERC’s McIntyre Loses Cancer Battle

By Rich Heidorn Jr.

Former FERC Chairman Kevin J. McIntyre died Wednesday following an 18-month battle with a brain tumor that had sidelined him since last summer.

McIntyre, 58, relinquished the chairmanship Oct. 24 after revealing that he had suffered a “serious setback” in his cancer fight. (See McIntyre Steps Down; Chatterjee Named FERC Chair.)

The chairman’s health had become the subject of increasing speculation since a fall that left him visibly uncomfortable at the commission’s July open meeting.

Change in Appearance

McIntyre seemed healthy when he and fellow nominee Richard Glick testified at their Senate confirmation hearing in September 2017, but he had a shaved head when he was sworn in as chairman three months later.

Last March — as E&E News was about to publish a story detailing his cancer diagnosis — McIntyre explained his appearance, issuing a statement saying he had undergone “successful surgery” for a “relatively small” brain tumor discovered unexpectedly in summer 2017.

“I was advised … that, with the surgery and subsequent treatment behind me, I should expect to be able to maintain my usual active lifestyle, including working full time, and that expectation has proven to be accurate,” he said then.

He appeared healthy in May, when he was the keynote speaker at the Energy Bar Association’s annual meeting. (See “McIntyre Recalls First Day at FERC,” Overheard at EBA Annual Meeting.)

Kevin McIntyre seemed healthy when he testified at his Senate confirmation hearing in September 2017, but he had a shaved head when he was sworn in as chairman three months later, following surgery to remove a brain tumor. He was clearly uncomfortable at his last FERC open meeting in July, following a fall that left his arm in a sling. | ©  RTO Insider

At the July open meeting, however, he wore a sling and appeared uncomfortable after disclosing he had injured his arm and suffered compression fractures in two of his vertebrae in a fall. It was the last meeting he would attend and one of his last public appearances.

In September, Commissioner Neil Chatterjee began FERC’s open meeting by reading a statement in which McIntyre apologized for his absence, saying his “ongoing recovery” prevented him from attending.

At the October meeting, Chatterjee said simply: “Chairman McIntyre is not here. My prayers are with him and his family.”

A week later, McIntyre issued a statement saying he would remain on the commission but would relinquish the chair’s role “and its additional duties so that I can commit myself fully to my work as commissioner, while undergoing the treatment necessary to address my health issues.” However, he did not participate in any orders following his statement.

In their opening remarks at FERC’s last meeting Dec. 20, the commissioners wished McIntyre and his family well for the holidays. But unlike at earlier meetings, none of them offered hopes of him returning to work.

Accomplishments

Before relinquishing the chairmanship, McIntyre and the commission approved major orders on energy storage, generator interconnections and transmission rates, and opened an inquiry on gas pipeline licensing. Last January, he led a 5-0 vote rejecting the Department of Energy’s proposed bailout of coal and nuclear generation, instituting a new resilience docket. (See Ailing Chair, Resilience Inquiry Topped FERC News in 2018.)

McIntyre joined FERC after two decades at Jones Day, where he represented energy clients in administrative and appellate litigation, compliance and enforcement matters, and corporate transactions. A graduate of San Diego State University and Georgetown University Law School, he was co-leader of Jones Day’s global energy practice.

He is survived by his wife of 10 years, Jennifer Brosnahan McIntyre, chief counsel for Boeing Defense’s Autonomous Systems unit, and three children, Lizzie, Tommy and Annie. McIntyre’s mother, Alice L. McIntyre, was a retired pastoral counselor, and his father, John R. McIntyre Jr., was a retired Air Force colonel.

McIntyre’s widow released a statement through FERC thanking “the entire FERC family for their hard work every day for the American people and for their faithful support of Kevin during his time at the commission, especially in the last few months.”

“Kevin often said that being chairman of FERC was his ‘dream job’ — he truly loved and believed in the agency, its mission and its people,” she said. “He was always energized by the challenge of leading the agency ‘full steam ahead,’ even when his health faltered. His commitment to his duty, and his faith in the FERC team, never wavered. We will always be grateful for the opportunity, however brief, that Kevin had to serve our country as FERC chairman.”

FERC Chief Administrative Law Judge Carmen A. Citron swears in Kevin McIntyre as his wife, Jennifer Brosnahan McIntyre, looks on. | FERC

Condolences

“Today is a deeply sad day for the Federal Energy Regulatory Commission and for all those who had the pleasure of knowing Kevin McIntyre both personally and professionally,” Chatterjee, who replaced McIntyre as chairman, said in a statement. “During his tenure at the commission, Kevin exhibited strong leadership and an unmatched knowledge of energy policy and the rule of law. He exemplified what it means to be a true public servant each and every day, no matter the challenges that lie ahead of him.

“In the face of adversity, Kevin’s dedicated faith, devotion to family and sharp wit never faltered. His unwavering strength was — and will continue to be — an inspiration to us all. I will miss the wise guidance of my colleague, the dear camaraderie of my good friend and the frequent banter with my fellow sports fanatic, Kevin.”

Commissioner Cheryl LaFleur said the commission “was very fortunate to have Kevin McIntyre at the helm for as long as he was, and I was honored to serve with him. I particularly appreciated his keen legal judgment, unstinting commitment to the rule of law and deep concern for the organization even in the face of his personal struggles. On a personal level, I appreciated his warm collegiality and ready Irish wit, and was frequently charmed by his Catholic school vocabulary.”

Glick said he got to know McIntyre during the confirmation process. “It did not take long to recognize that Kevin was a man of great intellect and principle. He brought both qualities to the Federal Energy Regulatory Commission where, as chair, he guided the commission to bipartisan consensus during a particularly tumultuous time,” Glick said. “But there was much more to Kevin than being a FERC chairman. He was extremely kind and witty. I most enjoyed our conversations about our respective lives. Kevin often spoke glowingly about his wife, Jenny, and their three wonderful children … and never failed to inquire about my family.”

Sen. Lisa Murkowski (R-Alaska), chair of the Energy and Natural Resources Committee, also expressed condolences for McIntyre. “As a lawyer, a commissioner and as FERC’s chairman, he always had the utmost respect for the agency and its mission. He was as warm and engaging as he was knowledgeable about the issues that came before him.”

Rep. Greg Walden (R-Ore.), ranking member of the House Energy and Commerce Committee, said McIntyre’s “expansive knowledge and expertise of energy law was a tremendous asset to the commission’s important responsibilities and helped shape U.S. energy policy for years to come.”

John Moore, director of the Natural Resources Defense Council’s Sustainable FERC Project, said McIntyre “led FERC with a steady hand and with an emphasis on preserving open electricity markets and maintaining the independence of the commission. We especially salute his high civic calling.

“As we look to the future, we urge Congress, the administration and the commission itself to preserve both the spirit and letter of fairness and evenhandedness that marked Chairman McIntyre’s tenure,” he added.

“He was smart and kind, and I was glad to have met him, even briefly,” said Katherine Hamilton, former president of the GridWise Alliance.

Successor to be Named

McIntyre’s term would have expired on June 30, 2023. His death leaves FERC with two Democratic and two Republican commissioners, including Bernard McNamee, who joined the commission Dec. 11 but has not yet begun voting on orders.

Once McNamee begins to vote, analysts at ClearView Energy Partners noted Thursday, FERC could face 2-2 deadlocks on votes on “LNG terminals and natural gas pipelines, and potentially on orders that impact the fuel mix of the electric generation sector.”

“It is not clear yet whether Senate Minority Leader Chuck Schumer (D-N.Y.) will try to press [Majority Leader Mitch] McConnell [R-Ky.] and/or the White House to either renominate Cheryl LaFleur — whose term expires on June 30 — or nominate a different Democrat to FERC at the same time as a replacement for McIntyre,” the analysts said. “While conventional wisdom would suggest that pairing a Republican and Democrat (given LaFleur’s expiring term) could smooth the confirmation process, the reality that a simple majority suffices to confirm nominees likely makes this prior custom far less relevant.”

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Critics: CEII Rule a Trojan Horse for Coal, Nuke Bailouts

By Rich Heidorn Jr.

Environmental and public policy advocates last week challenged the Department of Energy’s proposed procedures for designating critical electric infrastructure information (CEII), saying it denies due process and could be a Trojan horse for the department’s efforts to subsidize coal and nuclear generation.

DOE announced its proposed procedures Oct. 29 under the 2015 Fixing America’s Surface Transportation (FAST) Act, which gave both FERC and the secretary of energy authority to designate information as CEII and thus exempt from disclosure.

Decision Tree for Making CEII Determinations on Dam Safety Documents | FERC

Among those weighing in in support of the rule before the comment period closed last week were the Edison Electric Institute, which said the rules would help encourage “information sharing frameworks” between government and private industry that are essential for responding to cyberthreats. PJM also filed in support.

But Earthjustice, the Union of Concerned Scientists, and Public Citizen filed joint comments opposing the rule, calling it “a breathtaking” overreach of the department’s authority that “would inappropriately broaden the department’s authority to restrict access to information critical for informed debate on issues important to the public.”

The groups said although the FAST Act gives both FERC and DOE authority to designate information as CEII, only FERC has authority to set the “criteria and procedures” for doing so. FERC, which issued its procedures in 2016, rejected a rehearing request on its order in May. (See FERC Clarifies CEII Rules, Denies Rehearing.)

DOE proposed that industry and other stakeholders could request information they submit to DOE be “pre-designated” as CEII and remain so on an “interim” basis pending DOE review, preventing disclosure under the Freedom of Information Act (FOIA).

“Information that is pre-designated or provided interim treatment would be handled like CEII indefinitely; the department commits only to ‘endeavor to make a determination as soon as practicable’ regarding its actual status as CEII,” the groups said. “… The proposed rule would functionally shift the role of designating CEII from the department to industry stakeholders, as the assertions of entities submitting the information provides the basis for treatment as CEII indefinitely.”

The rule is unnecessary, the groups said, because FOIA rules and FERC’s CEII procedures already allow for review of sensitive information before its release.

Tyson Slocum, director of Public Citizen’s Energy Program, said the rule would give DOE the “foundation” to seek coal and nuclear bailouts on national security grounds. “Right now, DOE lacks a process by which it can designate infrastructure on national security or national defense grounds,” Slocum said in an email. “This rule would provide that authority.”

‘Critical Defense Facilities’

Energy Secretary Rick Perry | © RTO Insider

In June, a leaked “pre-decisional” memo proposed that DOE require RTOs and ISOs to purchase energy or capacity from “fuel-secure” generators at risk of retirement for 24 months while the department identifies “Critical Defense Facilities” served by “Defense Critical Electric Infrastructure (DCEI).” (See Trump Orders Coal, Nuke Bailout, Citing National Security.)

In October, numerous press reports indicated that the White House had rejected DOE’s proposal following opposition from the National Security Council and National Economic Council. But there has been no official word on the plan’s demise. (See Chatterjee Dodges as DOE Spins on Coal Bailout.)

“Should the DOE be granted the authority it seeks in this proposed rulemaking, then the agency can designate as secret the methodology used to determine that certain infrastructure is critical for defense or national security,” Slocum said. “Once it has made that designation, the agency could then justify multi-billion-dollar bailouts to the owners of such facilities, and groups like Public Citizen would be unable to challenge it, since the underlying justification would now be classified. Therefore, stopping this rule is central to stopping the Trump administration’s coal and nuclear bailout.”

‘Much Care’

In contrast, EEI said it generally supports the proposal. “It is clear that much care and thought went into the preparation of the proposed rule, and the tone set demonstrates the department’s commitment to promoting public/private sector information sharing,” EEI said. “EEI supports this commitment because public and private sector entities must partner to protect the nation’s critical electric infrastructure and public/private information sharing is a crucial element to achieving that goal.”

However, EEI said DOE should specify deadlines for acting on CEII requests and ensure all DOE offices, FERC, the Department of Homeland Security and Nuclear Regulatory Commission use consistent criteria in making designations.
PJM also supported the proposal and said it should be amended to include penalties for willful disclosures of sensitive information.

“The final rule should ensure that disclosure of this information is subject to a DOE review of the requester’s actual ‘need to know’ this highly sensitive information,” PJM said. “Too often in the past, CEII disclosure rules have been written by [FERC] and other agencies to establish procedures with a going-in assumption of implementing the requester’s right to know the critical information in question.”

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ERCOT Faces Tight Summer Margins, Market Changes

By Tom Kleckner

Having survived record temperatures despite slim reserve margins last summer, ERCOT is preparing to take on the Texas heat again in 2019 with reserve margins that have shrunk even further.

The grid operator said in December that canceled gas projects, other delayed projects and increasing demand from oil and gas production had reduced its reserve margin to a historic low of 8.1%. (See ERCOT Predicts Tight Reserve Margin for 2019.)

ERCOT said it will have more than 78 GW of operational capacity — 600 MW more than expected last May — available this summer to meet projected demand of 74.9 GW. ERCOT had an 11% reserve margin last summer, when it met a record peak of 73.5 GW and 13 other demand intervals above the previous high without resorting to emergency actions.

The reserve margin is expected to grow to 12.2% in 2021, within reach of ERCOT’s target planning margin of 13.75%. It is then expected to fall to 7.5% in 2023, when available capacity is projected to flatten, while industrial load growth continues to scale up.

ERCOT faces historically low reserve margins next year in the face of expected increases in demand. | ERCOT

But no worries, says ERCOT. “What we’re encountering now is nothing new,” Pete Warnken, the grid operator’s manager of resource adequacy, said in December.

Texas Public Utility Commission Chair DeAnn Walker has called the 8.1% reserve margin “very scary.” Yet, given a chance to discuss market changes to ensure continued reliability, the PUC in December twice declined to take up the issue during its open meetings. Staff say the commissioners want more time to study stakeholder input, consultant studies and other recommendations, and that they want to “get it right.”

ERCOT’s energy-only market was supposed to incent new generation. Rather than finance new plants on the backs of the ratepayers, the Texas model shifts the risk to investors who might benefit from high power prices.

However, ERCOT’s wholesale prices are among the lowest in the nation, hovering around $25/MWh the last few years. Uneconomic coal-fired plants — like Luminant’s three last year — have closed down or will close down. CPS Energy’s announced shutdown of J.T. Deely at the end of 2018 means almost 5 GW of coal generation have been taken out of the market in the last two years.

Power producers want to increase the payouts from ERCOT’s operating reserve demand curve (ORDC), which provides a price adder during periods of generation scarcity. During an October workshop on electricity prices, Exelon said the change would result in an annual $4 billion increase in electricity prices.

“Prices have to go up. They do!” Bill Berg, Exelon’s vice president of wholesale market development, said at the time. Without the increase, he said, prices won’t support the needed investment.

That $4 billion number has been thrown around by opponents to ORDC changes, which include consumer advocates and the conservative Texas Public Policy Foundation.

“Let the market work,” urged Bill Peacock, the foundation’s vice president of research, in a Dallas Morning News op-ed.

Former FERC Commissioner Pat Wood, who also chaired the PUC when ERCOT’s deregulated market was established in 1999, doubts the $4 billion figure, saying that is “nowhere near” the necessary cost. Wood says “the cheapest and most market-oriented way” to plan for the future is to continue to rely on the ORDC.

The Texas PUC faces tough discussions on the ERCOT market this year. | © RTO Insider

The PUC is also pondering whether to incorporate marginal line losses into how it allocates transmission costs among power generators, an idea being pushed by NRG Energy and Calpine.

Unlike other states, Texas shares the cost of lost electricity among all generators evenly. The allocation process and nearly $7 billion worth of transmission infrastructure has resulted in Texas, with nearly 23 GW of capacity, becoming the top producer of wind energy in the U.S.

Critics say the marginal line-loss proposal would suppress the continued development of wind and solar projects, which far outnumber gas generators in ERCOT’s interconnection queue.

While the PUC weighs which, if any, changes to make, Texas policymakers could also have a say. The 86th Texas Legislature will open for business on Jan. 8 and will end its biennial session May 27.

Legislators have already filed more than 100 bills that could affect the Texas energy market and its consumers. Many of those will inevitably die, but one to watch is Senate Bill 76. The legislation would create a Grid Security Council comprising appointees by Texas Gov. Greg Abbott, including ERCOT representatives, to monitor issues that touch on grid security.

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Trump Administration Fiddled While California Burned

By Rich Heidorn Jr.

WASHINGTON — 2018 brought chilling warnings about the growing dangers of climate change — and seeming evidence of it in November’s Camp Fire that killed more than 80 people and destroyed almost 19,000 structures and the town of Paradise, Calif. It was the state’s most destructive wildfire on record.

The November 2018 Camp Fire was the most destructive in California history. | CalFire

A month before the fire, the U.N.’s Intergovernmental Panel on Climate Change issued a report saying climate change could have catastrophic effects sooner than previously thought and calling for an unprecedented global response.

In November, a congressionally mandated report by the federal government predicted that if carbon emissions continue to grow at historic rates, some economic sectors will see hundreds of billions of dollars of annual losses by the end of the century — “more than the current gross domestic product of many U.S. states.”

President Trump told reporters he had read “some of” the report but didn’t believe its findings. Just two days before the report was released, he tweeted, “Brutal and extended cold blast could shatter ALL RECORDS. Whatever happened to global warming?”

Pruitt, Zinke Depart; Dems to Take House

Despite the resignations of two of the president’s most controversial cabinet members, EPA Administrator Scott Pruitt and Interior Secretary Ryan Zinke, the administration’s efforts to reverse Obama administration policies on climate and the environment continued unabated in 2018.

In August, acting EPA Administrator Andrew Wheeler, a former coal industry lobbyist, announced the replacement for the Obama Clean Power Plan. The Affordable Clean Energy (ACE) rule defines the “best system of emission reductions” as heat-rate efficiency improvements that can be achieved at individual coal plants, in contrast with the CPP, which set state emissions limits and encouraged switching to natural gas and renewables. Compared to the CPP, EPA said, ACE will cut electric prices by up to 0.5% in 2025 while increasing coal production for power sector use by up to 5.8%.

In December, Wheeler proposed eliminating the requirement that new coal-fired generation incorporate carbon capture technology. Given competition from lower-cost natural gas and renewables that has cut coal’s market share, it was a largely symbolic measure. EPA acknowledged no new coal-fired generating units are likely to be built in the U.S.

President Trump signing his executive order seeking to undo the Clean Power Plan as coal miners, Interior Secretary Ryan Zinke, EPA Administrator Scott Pruitt and Vice President Mike Pence watch.

The Energy Information Administration said U.S. coal consumption will fall to 691 million short tons (MMst) in 2018, a 4% decline from 2017 and the lowest level since 1979. About 11 GW of coal-fired generating capacity retired in the first nine months of 2018 with another 3 GW of retirements expected in the last quarter, making the year second only to 2015 in retirements. An additional 4 GW is expected to retire by the end of 2019. (See related story Critics: CEII Rule a Trojan Horse for Coal, Nuke Bailouts.)

On Friday, EPA proposed changing its cost-benefit calculations to eliminate the “co-benefits” of reducing pollutants other than those being targeted. Had the rule been in place, EPA said, it would have prevented the 2011 Mercury and Air Toxics Standards, which pushed many coal generators into retirement. The Obama Administration’s EPA said although the MATS rule would cost utilities $9.6 billion a year and produce only $6 million in direct public health benefits, it was justified by co-benefits of reducing soot and nitrogen oxide, saving at least $37 billion in annual health costs and lost workdays.

A Change in the House

Democrats picked up about 40 House seats in the midterm elections, giving them control of the lower house when Congress convenes its new session Jan. 3. Rep. Frank Pallone (D-N.J.), who will become chairman of the Energy and Commerce Committee, has pledged “robust oversight of the Trump administration’s ongoing actions to sabotage our health care system, exacerbate climate change and weaken consumer protections.” Rep. Raúl Grijalva (D-Ariz.), who will chair the Natural Resources Committee, says he will seek to elevate discussions on climate change while increasing oversight of the administration.

In the Senate, where Democrats lost two seats, West Virginia Democrat Joe Manchin will replace Sen. Maria Cantwell (D-Wash.) as ranking member of the Energy and Natural Resources Committee, although his outspoken support for coal will place him at odds with most of his party.

Progressive Democrats are pushing the idea of a Green New Deal to transition the U.S. to 100% renewable energy. Although it has no chance of passing with Trump in the White House and Republicans still controlling the Senate, advocates said it could help frame the issue for the 2020 presidential and congressional races.

“Climate change is clearly back on the table as a priority issue for the Democratic Party,” Dylan Reed, head of congressional affairs for Advanced Energy Economy (AEE) said in a year-end webinar Dec. 18.

Renewables Continue to Gain Share

Despite the Trump administration’s cheerleading of fossil fuels at home and abroad, states and businesses accelerated efforts to increase renewable generation and reduce emissions in 2018.

As of August, nonutility buyers had contracted for more than 3.5 GW of renewable energy in 2018, breaking the annual record of 3.12 GW set in 2015.

In October, the U.S. marked 1 million electric vehicles sold, with 2018 sales up more than 50% over the year before. While EVs represented only 2% of vehicles sold in 2018, electrification is being embraced more quickly in other transportation areas, with electric buses now more than 10% of new sales. State regulators approved $880 million in EV charging infrastructure in 2018 with another $1.5 billion in proposals pending, according to AEE.

The Electric Power Research Institute predicts that EVs and other electrification efforts could result in load growth of 24% to 52% by 2050.

Renewable prices continued to fall during the year.

| Lazard Levelized Cost of Energy Analysis

In November, Lazard’s annual Levelized Cost of Energy Analysis found that onshore wind costs have dropped to $29-$56/MWh, with utility-scale solar at $36-$44/MWh — matching or bettering natural gas combined cycle plants at $41-$74/MWh. Coal is higher than all of them at $60-$143/MWh.

Offshore wind costs also are dropping. Vineyard Wind, an 800-MW project off the Massachusetts coast, will provide power and renewable energy credits at a levelized price of 6.5 cents/kWh in 2017 dollars. “That’s pretty much comparable to [Massachusetts’] big hydro power contract procurement at … a levelized cost of energy of 5.9 cents,” said AEE spokesman Bob Keough.

Since Trump announced plans in June 2017 to withdraw from the Paris climate agreement, 17 states have joined the U.S. Climate Alliance and pledged to honor U.S. commitments, according to AEE.

In September, California lawmakers approved legislation to get 100% of its power from renewable and other zero-carbon resources by 2045. Six other states — Nevada, New Mexico, Colorado, Maine, Michigan and Illinois — also are pledging to move toward a 100% clean grid, AEE said.

Missouri adopted a green tariff allowing Ameren customers to get up to 100% of their load from renewables, said J.R. Tolbert, AEE’s vice president of state policy. “This is sort of the proverbial camel’s nose under the tent,” he said. “We expect to see more green tariffs in the Midwest as a result of what happened in Missouri.”

Environmentalists fared less well at the polls in November, with voters in Arizona, Nevada and Washington rejecting initiatives following expensive campaigns.

AEE’s Reed said the Trump administration’s efforts to bail out coal power forced clean energy advocates to produce legal and financial analyses opposing the proposals. “This required a lot of time, effort and resources that could have otherwise been used to accelerate the transition” to cleaner energy, he said.

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PJM Ponders New Capacity Rules — Again — in 2019

By Rich Heidorn Jr.

PJM ended an era in 2018 with the retirement of Chairman Howard Schneider, who had served on the Board of Managers since the RTO’s inception in 1997. But in many ways, the year was much like those before, with capacity and energy market rules under constant redesign. Some stakeholders have grown weary of the churn.

The year also saw battles between transmission owners and load interests and the biggest default in PJM history, which raised questions about the RTO’s credit practices.

Here’s a review of some of the biggest PJM stories of 2018, and a look at what’s ahead in 2019.

Former PJM Board Chairman Howard Schneider and CEO Andy Ott listen to consumer and public advocates at last year’s PJM annual meeting. | © RTO Insider

Capacity

2017 ended with PJM and its stakeholders at odds over the best way to insulate the capacity market from state-subsidized generation. RTO officials had rejected the Independent Market Monitor’s proposal, endorsed by stakeholders, to extend the minimum offer price rule (MOPR) to all units indefinitely, with carve outs for states’ renewable portfolios and public power self-supply.

PJM’s board responded by asking FERC to choose between the IMM plan and staff’s capacity repricing proposal, under which the RTO would have accepted bids from subsidized resources in its capacity auctions but then isolate them during a second stage and reset the price without them (ER18-1314).

FERC rejected both proposals and ordered PJM to expand the MOPR — which now covers only new gas-fired units — to all capacity receiving out-of-market payments, including renewable energy credits. The commission recommended creating an “alternative” fixed resource requirement allowing states to pull subsidized resources and associated loads from the capacity auction. The 3-2 ruling, which partially granted a 2016 complaint led by Calpine (EL16-49), initiated a Section 206 proceeding in a new docket (EL18-178).

PJM responded with an Oct. 2 brief outlining its proposal for an “extended resource carve out” that would allow subsidized resources to obtain capacity commitments without clearing the capacity market, while creating a mechanism to restore prices to “the theoretically correct competitive level.”

“Making room, outside the auction, to accept subsidized generation as a PJM ‘capacity resource’ ineluctably will degrade auction prices,” PJM said. “Unless the commission is prepared to accept a mechanism to adjust prices to their ‘correct’ level, this trade-off must be understood as an unavoidable consequence that comes once uneconomic resources are relieved from having to participate in the market.” (See Little Common Ground in PJM Capacity Revamp Filings.)

Stakeholders offered at least seven other alternatives for the MOPR and numerous modifications on FERC’s FRR concept and PJM’s carve out. In initial filings and reply comments filed in November, the stakeholders generally fell into two camps. One argued for a rejection of any carve out, calling instead for a “clean,” MOPR-only construct that extended to all resources. The other generally supported the concept of the FRR Alternative but argued that because of the repricing mechanism, PJM’s extended resource carve out would inflate capacity prices. (See PJM Stakeholders Hold Their Lines in Capacity Battle.)

The stakes are large, as illustrated by two of the most recent filings in the docket. On Dec. 6, eight generation developers, including Calpine and Tenaska, warned that the FRR Alternative “would in fact end the competitive PJM capacity market as we know it,” without a mechanism to avoid price suppression of competitive resources.

Public power and renewable advocates, including the American Public Power Association, the National Rural Electric Cooperative Association and the Natural Resources Defense Council, responded with a Dec. 21 letter to the commission. “We agree that states and locally governed utilities have the authority to make resource choices, and that it is not the role of the Regional Transmission Organization (RTO) to shield market participants from the effect of those policies,” they said.

BRA Results ‘Not Competitive’

In 2018, the second Base Residual Auction, in which all resources had to meet the Capacity Performance requirements, saw prices jump 83% in most of the RTO. But the IMM reported in August that the results of the auction were “not competitive” because prices were not capped at the net avoidable cost rate. The analysis said offers exceeding net ACR, while permitted by current rules, amounted to “economic withholding” and boosted total auction revenue by 41.5%. PJM insisted the rules had been followed, saying “the proper forum for such concerns about competitiveness of offers is the Federal Energy Regulatory Commission.”

The Market Monitor’s analysis found that clearing prices in the 2018 Base Residual Auction would have been lower everywhere but the PSE&G zone had prices been capped at net avoidable cost rate. Not identified is the DEOK zone, which cleared with the rest of the RTO at $140/MW-day, but would have priced at $128/MW-day. | PJM, Monitoring Analytics

In April, the commission held a technical conference to consider whether the RTO should move from a year-round to a seasonal capacity construct. Although it has yet to issue an order on the merits of the issue, FERC signaled its concerns in denying rehearing requests in the docket in August (EL17-32, EL17-36). “Given that PJM is a summer peaking system, … the move to a single, annual capacity product may have pushed valuable summer-only resources out of the capacity market and thereby increased capacity costs with little or no reliability benefit,” it said.

While it’s not known when or how FERC will rule on these issues, one thing is clear: State officials will be upset with any rules that make their initiatives more difficult or more costly.

States’ efforts to preserve their nuclear fleets continued in 2018, with New Jersey approving zero-emission certificates (ZECs) in May. In September, a federal appellate court upheld a similar program in Illinois, ruling the initiative did not violate the Federal Power Act.

After a year in which some state regulators threatened to leave the RTO or end the capacity market, RTO officials are in a very difficult spot.

“Almost nobody is happy with the state of [PJM and ‘Almost Nobody is Happy’ with Capacity Markets at Conference.)

Aiding Coal, Nuclear Generation

In the energy market, PJM officials are trying to win stakeholder approval for a plan to allow large, inflexible generators such as coal and nuclear plants to set market prices. PJM’s board told stakeholders in December that it will make a unilateral FERC filing supporting its price formation proposal if they do not act by Jan. 31. Stakeholders have heard first reads on three alternative proposals.

“We feel we are correctly criticized as a region for not addressing known price anomalies,” CEO Andy Ott told the Markets and Reliability Committee’s Dec. 20 meeting. “There is a very strong opinion by the board that we are long overdue for these changes.”

PJM also is pushing to compensate generators for their “fuel security,” another initiative that could benefit struggling coal and nuclear generators. PJM released a report on the issue in December, saying that while there is no imminent threat, “fuel security is an important component of reliability and resilience — especially if multiple risks come to fruition.”

PJM said the compensation could be achieved through the capacity market or through a winter reserve product in the energy market.

Regardless of what the RTO decides, the proposal is likely to be viewed skeptically by stakeholders representing load, who have long complained of the costs of PJM’s large reserve margins and increasingly restrictive Capacity Performance rules.

Transmission Owners vs. Load

Load interests spent much of 2018 battling with transmission owners over their supplemental projects, which address individual planning criteria and are not subject to competition or PJM’s analysis for inclusion in its Regional Transmission Expansion Plan. In September, FERC approved TOs’ compliance filing in response to the commission’s February show cause order requiring them to increase stakeholder engagement in the development of supplemental projects (EL16-71, ER17-179). (See FERC Upholds PJM TOs’ Supplemental Project Rules.)

PJM’s Transmission Replacement Processes Senior Task Force meets earlier this year. | © RTO Insider

FERC also weighed in on a highly charged cost allocation issue, saying the solution-based distribution factor (DFAX) method is unjust and unreasonable for projects that address stability-related reliability issues. (See FERC Rethinking DFAX for Stability Transmission Projects.)

In May, PJM stakeholders endorsed a proposal requiring PJM to evaluate cost commitments — including construction costs, return on equity and capital structure — in its analysis of competitive bids for transmission construction.

Western Market

PJM’s Stu Bresler (left) and Peak CEO Marie Jordan pitched their combined services at the Colorado PUC in March 2018. | © RTO Insider

In February, PJM and Peak Reliability, the reliability coordinator (RC) for the Western Electricity Coordinating Council (WECC), proposed creating an energy market as an alternative to the Western Energy Imbalance Market (EIM) managed by CAISO. But the effort quickly unraveled after CAISO said it would begin offering its own RC services at costs much lower than Peak’s. Seeing its customers defect to CAISO and a competing RC offering from SPP, Peak abruptly announced in July it would cease operations.

Ott said in October that PJM remains interested in the idea but that the pace of talks has slowed since Peak’s announced departure. (See Q&A: PJM’s Ott Still Looking West.)

GreenHat Default

In the cross fire between load and supply, PJM officials often take shrapnel over their policy choices. But the RTO rarely faces the kind of questions about its competence that followed the default of FTR trader GreenHat Energy.

GreenHat listed its address as Suite 565, 826 Orange Ave., Coronado, Calif. — a UPS store between a nail salon and a RiteAid. | Google

The company — run by two traders who were involved in a scheme to manipulate the CAISO and MISO markets between 2010 and 2012 — amassed 890 million MWh of FTRs (the largest FTR portfolio in PJM) with only about $600,000 of collateral.

The company’s collapse in June was the biggest default in PJM history. The incident led to calls for changes to PJM’s credit policy and questions about the RTO’s failure to respond promptly to warnings from other FTR traders, which allowed GreenHat’s $10 million loss in 2017 to grow to more than $100 million.

An investigative committee of the Board of Managers is expected to issue a report on what went wrong as soon as February.

Market Monitor: New Contract, More Oversight

The year also brought a new contract for Monitoring Analytics, PJM’s Independent Market Monitor, led by Joe Bowring.

The contract, which was extended through 2025, requires the Monitor to submit to an annual independent audit. In addition, the Board of Managers announced in December that it had hired former FERC General Counsel Michael Bardee as an external liaison to receive direct member feedback on the Monitor and report it to the board’s Competitive Markets Committee.