The American Wind Energy Association and The Wind Coalition have asked FERC to eliminate SPP’s “exorbitant” exit fee, saying it is a barrier to membership for independent power producers and others that do not own transmission or serve load (EL19-11).
The two wind energy advocacy groups filed a Section 206 complaint on Nov. 2 asking FERC to find the “Financial Obligations of Withdrawing Members” section of SPP’s bylaws and membership agreement unjust and unreasonable.
AWEA and The Wind Coalition said that, based on conversations with SPP staff, the exit fee charged to any non-TO or non-load-serving entity seeking to terminate its membership “could range from $700,000 to $1 million.” They noted that the exact amount is not known prior to termination, making it impossible for potential members to gauge their exit fee when considering membership in the RTO.
SPP said it is reviewing the complaint and will file a response at FERC, but it also told RTO Insider that the exit fee’s calculation is based on factors that include debt and financial obligations at the time of exit. A spokesman said the obligations “trend downward over time” and that the RTO frequently provides withdrawal estimates “to the dollar” for members.
The wind groups said the exit fee is “almost entirely intended to cover SPP’s existing and future obligations, which are unrelated to the exiting member.” They alleged exiting members are subsidizing future members’ business in the RTO, paying for costs for which they will receive no further benefit once they withdraw and for those they did not cause.
The groups also said SPP’s exit fee is unique among all other RTOs and ISOs, saying “no other organized market imposes general RTO/ISO costs on non-TO/non-LSE members through membership fees.” They said other grid operators only consider the withdrawing member’s open positions in the markets.
Wind farms and other independent power producers oppose SPP’s hefty exit fee.
“Other markets merely charge exiting members a nominal amount related to their obligations,” AWEA spokesman Evan Vaughan said. By discouraging participation from non-TOs and non-LSEs, Vaughan said, “consumer advocates, independent power producers, power marketers, energy storage, demand response and environmental groups are all, in effect, excluded from the decision-making process in SPP.”
“Membership in SPP is a meaningful designation,” the wind groups said in their complaint, referring to membership votes for SPP’s Board of Directors and initiatives, serving on stakeholder groups, and filing revision requests to change the Tariff.
“Simply put, without the ability to vote on SPP or provide leadership on SPP committees, non-members typically are unable to influence policy in a direction that considers or reflects their interests,” they argued. Noting SPP’s frequent claims to being a member-driven organization, they said “membership and the rights that it entails are critical.”
“We recognize the value of the diverse perspectives of our members and non-members, which is why we welcome them into our transparent stakeholder process,” SPP General Counsel Paul Suskie said in a statement.
Suskie noted SPP’s governance structure and the exit fee provision have been approved by FERC.
The wind groups agreed that SPP allows non-members to comment on initiatives and participate in the stakeholder processes, but they said, “Such participation is not the same as having membership rights.”
The Wind Coalition’s Steve Gaw, a founding member of SPP’s Regional State Committee as a Missouri regulator, is a regular attendee and frequent contributor to the discussion at stakeholder meetings. Gaw has long been open about his dissatisfaction with the exit fee, which has earned him playful ribbing from some members.
“We have been asking for changes to the exit fee in the SPP stakeholder process for several years, however, no changes have moved forward,” Gaw told RTO Insider via email.
AUSTIN, Texas — Shelly Botkin, the Texas Public Utility Commission’s newest member, has hardly followed a conventional path to becoming a utility regulator.
An avid reader, the Lubbock native chose comparative literature as her college major before finding her way into cultural anthropology. That led to several years as an English teacher in Mexico City, where Botkin honed her Spanish and toured the country. Eventually, she returned to the U.S. and enrolled in The University of Texas’ Institute of Latin American Studies, where she wound up bogged down in academic jargon.
“I found it difficult to communicate with ordinary people,” Botkin said. “It wasn’t for me.”
So what does one do with an anthropology degree? In 2000, Botkin’s only career choices were an entry-level job at the Texas State Capitol or a position with the advertising company behind the Southwest Airlines and “Don’t Mess With Texas” campaigns.
Botkin chose wisely and found herself answering phones and processing data in then-state Sen. David Sibley’s office. Sibley was one of the key architects behind Senate Bill 7, which had just deregulated the electric utility business in Texas.
After her first day on the job, she said, “I had to ask, ‘Somebody please tell me what Senate Bill 7 is about.’”
Sibley retired soon afterward, and Botkin spent the rest of the 2000s bouncing from one state political office to another. She worked for the lieutenant governor and in both the House of Representatives and the Senate, tackling air quality and electric utility issues, water policies and environmental regulations. Botkin was present for both the Competitive Renewable Energy Zone debates and the private-equity leveraged buyout of TXU, Texas’ largest utility.
She found the work fascinating, though it involved 750 bills in the House and 350 in the Senate each five-month session, depending on where she was.
“I spent 10 years learning how to pass or kill a bill. … I learned some important lessons,” Botkin said. “Do your homework and read the documents in front of you. Listen to people; talk to people; look for options. If you don’t know something, say you don’t know, then educate yourself. If you want people to understand your issues, you have to talk to them in a way that they understand you.”
Hitting Refresh
Botkin’s work attracted the attention of Theresa Gage, then ERCOT’s corporate communications director. Gage called Botkin in 2010 and asked if she would join the grid operator to run its governmental relations group.
“It was one of the best phone calls I’ve ever made,” said Gage, now ERCOT’s vice president of external affairs and corporate communications. “We promptly paid her back by putting her through one of the most incredibly stressful years known to the ERCOT market.”
At the time, the grid operator was focused on meeting a December deadline to go live with its delayed nodal market. ERCOT and the PUC were both facing sunset reviews to decide the agencies’ continued life, while the state was in the midst of a severe drought that would only be exacerbated in 2011 by a late-summer heat wave that pushed the Texas grid to the limit.
Botkin calls it a “meaningful exercise in crisis communications.”
“That was punishing,” she said. “I learned to hit refresh on the computer and [monitor] the prices and reserve levels.”
Although out of her comfort zone, Botkin said she gained a much better understanding of corporate governance and a business enterprise’s inner workings.
“She was a huge asset and helped us in immeasurable ways every single day,” Gage said.
When the Texas governor’s office reached out to Botkin earlier this year regarding a vacancy on the PUC, she hesitated. Noting the term is “a yearish” — it expires in September 2019 — and reflecting on her own job security at ERCOT, Botkin said her first reaction was, “I don’t know.” (See ERCOT’s Botkin Named to Texas PUC.)
But then she recalled her days at Girls State, a program designed to educate high school children on the duties, privileges and responsibilities of U.S. citizenship. As a teenager in the flat lands of West Texas, where, she said, “You feel like you’re in the middle of nowhere, but you feel like you’re the center of the universe.” Girls State helped Botkin escape the long shadow of her older brother and carve out her own place in the world.
“It gives you a sense of, ‘Why not you?’” she explained. “It’s not just ‘girl power.’ It gives you the impression that it’s going to be your turn to serve someday, so get in there and help the state move forward.
“The Girls State words started working on me. ‘I do know something about this. I can help.’ So far, it’s been great.”
‘A Spacious Place’
Botkin is a woman of few words on the bench, yielding to the more vocal DeAnn Walker and Arthur D’Andrea during the commission’s open sessions. Just don’t mistake that for a fear of public speaking.
“I’m not averse to speaking, but there’s so much talking behind the scenes that by the time we come out, there’s really not much to say,” Botkin said during a recent Gulf Coast Power Association luncheon address.
She may not be a lawyer like the other two commissioners, but “because of my legislative experience, I’m very aware words have meaning, and I understand why they do,” she told RTO Insider.
Botkin has quickly adapted to the pace of the regulatory world, where much of her time is spent reading legal filings and documents. She said she enjoys the certainty of making a dental appointment and keeping it. It’s a luxury she didn’t have at ERCOT.
“All the truisms about it are, in fact, true. ‘You’ll be spending a lot of time reading’; that’s 100% true,” Botkin said. “My role at ERCOT was up-to-the-minute, responding to things, getting back to people as soon as possible. In this role, there’s a lot more room to reach out into the future.”
And it’s a busy future for the PUC. Texas’ next legislative session begins in January, which means budgets and reports will be coming due. Commission staff have spent time at the Capitol reviewing the recent federal tax cut legislation and its effects on utilities. The PUC’s dockets include investor-owned utility rate proceedings, recovery of Hurricane Harvey’s costs, ERCOT market changes and the use of non-traditional technologies, such as battery storage, in electric delivery service.
Comments on the last issue are due Nov. 16, and Botkin is looking forward to reviewing them.
“It’s kind of hard to get their arms around it,” she said. “It’s like trying to pick up an octopus.”
Asked about the concept of wires companies owning storage assets, a concept opposed by many generators, Botkin said she has “no grand prognostication.”
“One of the reasons I find this industry so interesting is that things change. That’s interesting to me,” she said. “Given the schedule we have in the fall, I don’t think I’ll develop any Commissioner Botkin initiatives, because there’s plenty of work to do.”
Country crooner Mac Davis writes in his song, “Texas in My Rear View Mirror,” that he once thought “happiness was Lubbock, Texas, in my rear-view mirror.” It’s a common joke in Texas, one Botkin alludes to when she refers to the Lubbock area as “a spacious place.”
Botkin once felt the same way, but that was before she left Lubbock for Washington University in St. Louis and her anthropology degree.
“It’s the study of why people do what they do, why they think what they think and the institutions they create to organize their world,” she said.
And so, having studied the people and the institutions around her, Botkin has found her place in the world. For the time being.
Backers of energy-related ballot measures faced defeat on nearly every front in the West on Tuesday as voters in Arizona, Nevada and Washington rejected a series of proposals that became the subject of costly campaigns.
The lone exception: Nevadans overwhelmingly approved an ambitious clean energy standard that still faces a second hurdle two years from now.
Arizona
In Arizona, voters overwhelmingly rejected Proposition 127, a measure that would have required the state’s power providers to generate at least half their annual sales of electricity from renewable resources by 2030.
The measure was defeated roughly 70% to 30%, according to results posted on the Arizona Secretary of State’s website.
APS contended that passage of Arizona’s failed Proposition 127 would have threatened the economic viability of its massive Palo Verde nuclear generating station west of Phoenix. | Arizona Public Service
The race became a high-priced battle between competing interests. California billionaire Tom Steyer, whose environmental advocacy group NextGen America backed the proposal, and Arizona utilities, including Arizona Public Service (APS), spent more than $50 million in the fight.
Proponents argued Arizona should rely more on solar. “Arizona is America’s sunniest state, but only 6% of our energy comes from solar power. Prop. 127 takes advantage of our state’s unique potential to generate nearly unlimited, cheap, clean energy,” Alejandra Gomez, co-chair of Clean Energy for Healthy Arizona wrote in support of the measure.
The measure’s supporters said Arizona Public Service, the state’s largest utility, had wielded money and political influence for too long to maintain the status quo. In response to the measure’s failure, Prop. 127 campaign chairman Eric Hyers said that “the biggest thing we wanted in the cycle we already got, which is doing significant damage to APS’ stranglehold on our politics,” The Arizona Republic reported.
Opponents said Steyer was trying to impose California’s energy standards on Arizonans, with the potential to greatly increase their utility bills. California recently adopted legislation, SB 100, that requires the state to get 60 percent of its energy from renewables by 2030 and to use 100% zero-carbon electricity by 2045.
APS’ parent company Pinnacle West Capital fought Prop. 127, saying it could lead to the shutdown of the nation’s largest nuclear power plant, the Palo Verde Nuclear Generating Station, which sits in the desert about 45 miles west of downtown Phoenix.
“Nuclear power plants are designed to run at 100% every day of the year,” Donald Brandt, Pinnacle’s CEO, wrote in an open letter to Arizonans in September. “Maintaining the nation’s largest nuclear plant to the highest standards of safety and reliability while running only part-time makes for extreme operational and economic challenges.”
“Lest anyone think I exaggerate, a similar situation in California energy markets contributed to the recently announced closing of California’s Diablo Canyon nuclear plant,” the state’s last nuclear generating facility, Brandt wrote.
Southern California draws a significant portion of its energy from the Palo Verde plant in Arizona.
In a statement after Prop. 127’s defeat, Brandt said: “We’ve said throughout this campaign there is a better way to create a clean-energy future for Arizona that is also affordable and reliable. The campaign is over, but we want to continue the conversation with Arizonans about clean energy and identify specific opportunities for APS to build energy infrastructure that will position Arizona for the future.”
“As the nation’s largest producer of reliable emission-free energy, Palo Verde is the anchor of Arizona’s clean-energy future,” said Brandt. “Any serious plan to reduce carbon emissions has to include nuclear energy and Palo Verde.”
Nevada
Nevada voters went the opposite direction from their Arizona neighbors by approving new renewable energy mandates in the form of Question 6 by a vote of about 59% to 41%, the Nevada Secretary of State’s office reported.
The measure, also backed by Steyer and NextGen, would amend the state constitution to require utilities that sell electricity to retail customers in Nevada to source at least 50% of their energy from renewables by 2030.
Opponents insisted it would raise rates.
Constitutional amendments in Nevada must be voted on in two consecutive elections, so the ballot measure will be taken up again in 2020.
With regard to another ballot measure, Question 3, the state’s voters allowed NV Energy to keep its electricity monopoly in the state by 67% to 33% of votes counted.
The measure would have required the state legislature to provide for the “establishment of an open, competitive retail electric energy market that prohibits the granting of monopolies and exclusive franchises for the generation of electricity.” It would have allowed customers to exit NV Energy and obtain electricity from others without paying an exit fee.
Las Vegas casinos, which have had to pay hefty exit fees, helped finance the measure.
Question 3 was approved by 72% of voters in 2016, when NV Energy didn’t contribute. But this time around the utility, owned by billionaire Warren Buffett, reportedly spent $63 million to defeat the measure, while supporters doled out $21 million. That made it the most expensive ballot measure in state history with a combined $100 million in contributions over two election cycles.
Question 3 supporters vowed to continue their efforts to let Nevadans choose their energy provider.
Washington
Washington voters solidly defeated a ballot initiative that would have placed a fee on the state’s carbon emissions, with collected revenues used to fund environmental programs. I-1631 went down with 56% voting “no,” despite polls leading up to the election showing about 50% of potential voters favoring the measure and about 36% opposed.
Unlike a proposed “revenue-neutral” carbon tax (I-732) that failed to win passage in 2016, I-1631 was not designed to return its revenues back to residents. Instead, the monies raised by the fee would’ve been allocated to state-directed investments in “clean air and clean energy” (70%), “clean water and healthy forests” (25%) and rural communities heavily affected by climate change (5%).
The measure sought to charge energy producers and suppliers a $15/ton fee on CO2 emissions starting in 2020, rising $2/ton each year (plus inflation) until 2035, when the price would have hit an estimated $55/ton. While manufacturers were not to be directly subject to the fee, they would have paid indirectly through higher fuel costs.
The bill was broadly supported by groups and companies as diverse as the Sierra Club, Microsoft, Union of Concerned Scientists, the American Federation of State, County and Municipal Employees, the Service Employees International Union and several tribes in the state. Gov. Jay Inslee also backed the bill.
But opponents spent a state record $31 million to defeat the measure. The “NO on 1631” campaign was spearheaded by the Western States Petroleum Association and its top five contributors, including BP America, Phillips 66, Marathon Oil, American Fuel and Petrochemical Manufacturers, and Valero Energy. The editorial boards of most of the state’s newspapers also urged readers to vote against the measure. Investor-owned utilities in Washington largely stayed on the sidelines, only expressing opposition on grounds the carbon fee would raise electricity rates.
“Our coalition is tremendously grateful that an overwhelming majority of Washington voters looked at the facts about Initiative 1631 and overwhelmingly rejected this poorly written, costly and unfair measure,” said a message on the “No on 1631” group’s website.
In a blog post Wednesday, UCS President Ken Kimmell called the measure’s defeat a “major disappointment.”
“Unfortunately, the big oil companies, many of whom claim they support carbon pricing as a climate solution, spent about $30 million to defeat this initiative, arguing cynically that the initiative did not go far enough. This hypocrisy needs to be strongly called out,” Kimmell said.
Two members of SPP’s Regional State Committee (RSC), Republican utility commissioners Randy Christmann of North Dakota and Kristie Fiegen of South Dakota, won re-election to their seats Tuesday night.
Christmann is the projected winner against Democratic challenger Jeannie Brandt. With 95% of the precincts reporting, Christmann had 61.3% of the vote to Brandt’s 38.5%.
Kristie Fiegen | S.D. Public Utilities Commission
In South Dakota, Fiegen nearly doubled Democrat Wayne Frederick’s vote total, 65.5% to 34.5%.
New Mexico’s Patrick Lyons, who is cycling off the RSC, was less fortunate. The Republican lost his bid to return to the State Land Office against Democratic newcomer Stephanie Garcia Richard, 50.8% to 43.5%.
Lyons was term-limited from New Mexico’s Public Regulation Commission. He served two previous terms as the state land commissioner, considered to be one of the most powerful elected positions in New Mexico.
Elsewhere, Bob Anthony was elected to a sixth and final term on the Oklahoma Corporation Commission. The Republican garnered 60% of the vote against Democratic challenger Ashley Nicole McCray to hold on to a seat he has held since 1989.
OCC Chair Dana Murphy, who earlier this year lost her own bid for lieutenant governor, is the commission’s representative on the RSC.
LaFleur, Stakeholders Anxious over NERC Retirement Study
By Rich Heidorn Jr.
ATLANTA — FERC Commissioner Cheryl LaFleur and several stakeholders expressed concern Tuesday that “fuel war” partisans could weaponize NERC’s coming analysis on the impact of a dramatic increase in coal and nuclear plant retirements.
But based on the comments at Tuesday’s meeting, the analysis’ release may be delayed as stakeholders debate ways to prevent its findings from being taken out of context.
NERC Board Chair Roy Thilly said the assessment is “the most sensitive” NERC has performed in his seven-plus years on the board and promised the board won’t release it “until we’re comfortable” with it. We have to be “very, very, carful about enabling quotes out of context,” he said.
‘Scare Tactic-ish’
But LaFleur said the scenarios — based on an Energy Information Administration identification of units facing financial stress — were “scare tactic-ish.”
“The primary thing that makes generation retire is new generation … that’s what’s pushing this to happen,” she said.
“If there’s a specific issue, like frequency response or inverter issues or lack of black start or something else, let’s jump right on it, but I want to be sure that we don’t make an issue by the way we model it.”
The study is “so macro and worst-case it almost overwhelms the specific solutions.”
John Hughes, CEO of the Electric Consumers Resource Council, which represents industrial customers, was even more blunt, calling the scenarios “fiction.”
“Should NERC be issuing fiction, especially at this time, with the conspiracy within the industry to try to do a second round of stranded costs recovery of generation that should have been retired years ago?” he asked. “ … So, this is the battle that NERC is falling into. Any caveat or nuance it puts in the study will be missed by politicians and newspapers. They will take this study and run with it and make a fool out of this organization.”
Thilly lamented that S&P Global Market Intelligence published a story Sept. 5 based on a leaked “very early” draft of the analysis, saying the disclosure “really undercuts our process.”
The story was headlined “Power outages possible if coal, nuclear plants close rapidly.”
NERC officials said the draft included even more extreme scenarios — increasing coal retirements to 60% and nuclear to 75% — that have since been eliminated because they did not materially impact the results.
Two Challenges
Moura agreed that the results should not be sensationalized.
“I can certainly … understand the difficulties of telling this stress test scenario story without getting the general public and industry and policy makers thinking that the sky is falling. It’s certainly not. There’s a lot of processes and backstops available both at the state level, at the market level and even at the federal level to ensure reliability.”
He said the analysis identified two challenges, including ensuring new transmission where needed to address voltage stability and thermal violations resulting from shifts in generation locations.
The second challenge is managing the “end state” after the transition — the ability to respond to extreme conditions such as the polar vortex and fuel disruptions. The latter could mandate new gas pipelines, he said.
He noted that Texas got through last summer without reliability problems despite losing 4,000 MW of coal-fired generation in spring with only a few months’ notice.
Moura defended the use of the EIA expanded retirement scenarios, saying such rapid shutdowns could result from new federal environmental policies or plant owner bankruptcies. “It helps us understand the worst-case scenario,” he said.
“We certainly don’t see this as the future,” he Moura added. “It’s an engineering study to understand … what the bookends are.”
Steve Naumann, vice president of transmission and NERC policy for Exelon, the nation’s largest nuclear generator, said NERC should not take any action to block dissemination of the analysis. “Why wouldn’t you want that information?” he asked.
“The core recommendation here is ‘manage it,’” said NERC CEO Jim Robb, adding the industry needs to ensure that ] capacity markets and reliability-must run generation are performing as intended to ensure reliability. NERC’s role should be the “conscience of the industry” and avoid the politics, he added at Wednesday’s quarterly Board of Trustees meeting.
“While it is possible for coal and nuclear retirements to exceed the current announcements and long-term industry outlooks, any such acceleration would also have feedback effects on power and natural gas prices that would tend to slow down any further retirements,” Brattle Group analyst Metin Celebi said in an email Wednesday. “With additional retirements, wholesale energy prices would increase due to lower expected reserve margins and more expensive resources setting the power prices, and natural gas prices would also increase due to an increase in the dispatch of natural gas plants. … The increase in power and gas prices would improve the economic viability of the remaining coal and nuclear plants at risk for retirement, hence acting as a brake on further retirements.”
FERC on Monday granted Ameren a rehearing on an incentive rate treatment for one portion of the company’s Grand Rivers transmission project while rejecting a simultaneous request for another segment.
The 500-mile project, which is currently under development, will span Illinois and extend into Missouri, creating a continuous 345-kV path from Iowa to Indiana.
The commission denied a rehearing for the Illinois Rivers component of the project, affirming part of its February ruling that found Ameren had failed to demonstrate why the “remaining risks and challenges” associated with both the Illinois Rivers and Mark Twain segments warranted a 100-basis-point incentive adder given the late stage of project construction. (See Ameren Rate Incentive Rejected by FERC.)
In its Nov. 5 order, the commission dismissed Ameren’s contention that its February ruling failed to recognize its own precedent in Pepco Holdings, Inc., which distinguished between incentives requested after a project is already completed and those requested when a project is nearly complete (ER18-463).
The commission said its February order made clear that projects being nearly completed does not necessarily preclude them from receiving incentive adders, but that such projects also face fewer challenges, a condition the commission found applied to Grand Rivers.
“Pepco does not stand for the proposition that all incomplete projects will receive [a return on equity] incentive based on the risks and challenges of a project, as Ameren Transmission appears to suggest. Rather, Pepco stands for the proposition that an applicant may not seek incentives for a project that is already complete; a project that is not yet complete is eligible for incentives,” the commission wrote.
The commission acknowledged that Pepco granted incentives to a project that was nearly complete, but that it no long believes that it is “appropriate” to provide incentives to such projects.
“Thus, while a project being under construction does not preclude it from incentives, the commission will consider how close the project is to completion when evaluating the risks and challenges of the project — with less risk typically attendant to projects that are further along in the construction process. We note that consideration of construction progress as part of the nexus test is consistent with commission precedent,” FERC said.
In this case, the commission found the Illinois Rivers component “failed to meet the nexus test,” given that it was 90% complete at the time of its December 2017 application for the adders, with four of its nine line segments already energized and all 10 of its substations in service.
But in granting a rehearing for the Twain component of the project, FERC agreed with Ameren’s argument that it should be evaluated on its own merits — separately from Illinois Rivers — as the project had not yet broken ground by the time of last December’s application.
The commission also determined the Twain segment qualifies for the risk-reducing incentives spelled out in FERC’s 2012 policy statement on promoting transmission investment in that it will unlock constrained wind generation and relieve chronic and severe congestion, resulting in $2 billion in production cost savings across MISO.
“We also note that the Mark Twain component was reviewed and approved as part of the MISO Transmission Expansion Plan 2011 portfolio of [multi-value projects], such that alternatives to the project have been considered in a relevant transmission planning process,” the commission noted.
Monday’s order reduced Twain’s potential ROE adder to 50 basis points, citing FERC precedent in its 2015 NYISO ruling on the Edic-to-Pleasant Valley line and its 2018 ruling on NextEra Energy’s Empire line in New York, both of which are 345-kV projects similar to Twain.
“We find that the Mark Twain component unlocks location-constrained generation and provides congestion relief in a range comparable to that of the projects awarded a 50-basis-point ROE incentive in NYISO and NextEra,” the commission said.
PG&E Corp. described its wildfire prevention efforts Monday in a third-quarter earnings call that outlined strategies to power down equipment in extreme weather conditions, install thousands of cameras and weather stations along power lines, and harden its grid across large areas of Northern California.
“This is a long-term approach to frankly de-risking our assets in these high fire-prone areas,” CEO Geisha Williams told analysts on the call.
The fire-prevention plans also are part of PG&E’s efforts to reassure nervous financial markets. The company has watched its stock price plummet in the past year as investors worried about its potential multibillion-dollar liability for a series of devastating fires in 2017.
In August 2017, PG&E’s stock hit a high of more than $70/share but had sunk to about $41 by February amid talk of potential bankruptcy. The price had climbed back to nearly $49 as of Tuesday.
On Monday, the company reported Q3 net income of $564 million ($1.09/share), compared with net income of $550 million ($1.07/share) for the third quarter of 2017.
Williams began the earnings call by acknowledging the one-year anniversary of the October 2017 fires that tore through California’s wine country in Napa and Sonoma counties and leveled a portion of the city of Santa Rosa. State fire officials have blamed the company’s equipment for some of those fires, while others are still under investigation.
Some estimates have suggested PG&E’s eventual liability could be up to $15 billion under California’s unique method of holding utilities strictly liable for damage caused by electrical lines and equipment under a legal doctrine called “inverse condemnation.”
That doctrine was the subject of debate this year as the state’s elected officials tried to deal with the threat of PG&E’s financial collapse in the wake of the fires. Gov. Jerry Brown proposed elimination of inverse condemnation as part of SB 901, a landmark wildfire prevention act he signed into law in September. (See Does California need a Catastrophic Fire Fund?)
‘Important Work Remains’
The bill eventually established a procedure by which utilities could issue bonds to pay off wildfire debts, but it did not get rid of inverse condemnation, as Williams noted in the call. She said efforts to reverse the legal doctrine would continue.
PG&E outlined its efforts to deal with wildfire threats in an earnings call Monday. | PG&E
“While we believe [SB 901] represents a constructive initial step, more important work remains,” Williams said. “This law provides for improved financial stability for the investor-owned utilities in the state. However, it does not address inverse condemnation, and it remains our firm view that this must be resolved through legislative reforms or legal challenges.”
Meanwhile, PG&E plans to file a wildfire mitigation plan with state regulators in February, as required by SB 901, she said.
Actions already underway include increased vegetation management and daily aerial patrols.
Over the next four years PG&E plans to install 600 high-definition cameras and 1,300 weather stations in fire-prone areas, Williams said on the call. And, she said, “in the next 10 years, we intend to upgrade our system across a targeted roughly 7,000 miles of our highest risk areas with stronger and more weather-resistant poles and insulated tree wire.”
“These plans will be further detailed in the 2020 general rate case that will be filed later this year,” Williams said.
PG&E also is using another, more controversial tactic in its fight against wildfires and wildfire liability.
For the first time, in mid-October, it proactively shut down power lines during what the company said were high-risk weather conditions in the northern San Francisco Bay Area and the Sierra Nevada foothills near Sacramento. (See PG&E Shuts Down Power to Prevent Fires.)
“When the weather improved, our crews conducted patrols across the entire 3,400 impacted miles of our power lines by helicopter, vehicle and on foot, identifying multiple lines that had sustained damage,” Williams said. “Service was restored to nearly all customers within about two days.”
Since then, the company has received numerous complaints from residential customers and businesses that sustained losses, including claims of spoiled food, according to The Sacramento Bee and other news outlets. PG&E filed a compliance report with the California Public Utilities Commission on Oct. 31 defending its decision, the news reports said.
Jamie Court, head of the advocacy group Consumer Watch, has called PG&E’s decision to shut off power to tens of thousands of customers “blackout blackmail.” Immediately after the shutdown in mid-October, he said it was unnecessary and was PG&E’s way of sending a political message. (See Fire Season Becomes Blackout Time in California.)
“They didn’t get inverse condemnation [changed]. They want to get out of liability forever for everything, and this is the way they send a signal,” Court told RTO Insider at the time. “The biggest power a utility has is the ability to turn off power.”
CHICAGO — Following the 2011 Fukushima nuclear disaster, German leaders ordered an immediate shutdown of the country’s oldest nuclear reactors and devised a plan to meet 80% of its power needs through renewables by 2050. Such a transition is unlikely in the U.S., attendees found out at a conclave last week of PJM stakeholders and their German counterparts.
The two-day Energy Trends Forum immediately followed the annual meeting of the Organization of PJM States Inc. (OPSI) and was sponsored by OPSI and Germany’s Federal Ministry for Economic Affairs and Energy.
“The biggest question will be: Will politics stay out of the game?” said Frank Peter, the deputy executive director of Agora Energiewende, a German think tank supporting the country’s planned transition to low-carbon energy production.
“What we’ve kind of found in the U.S. is that’s an unrealistic expectation,” said former FERC Commissioner Tony Clark, a senior adviser with D.C. law firm Wilkinson Barker Knauer.
Differences
Annegret Groebel, who heads international coordination for Germany’s Federal Network Agency, said the country’s transition has been aided by a generation surplus. It has less transmission congestion and less granular pricing because it uses a zonal system, while PJM’s LMP is based on a nodal framework.
Germany has also unbundled the industry so that owners of transmission, distribution and generation assets are separate. In PJM, a holding company such as Exelon can own all asset classes through subsidiaries.
Germans are also willing to spend whatever it takes to interconnect renewables and maintain extremely high reliability, German representatives said.
In PJM, state interests can inhibit development of transmission from renewable resources to load centers. “If Pennsylvania doesn’t want energy from Iowa, then those lines serve no purpose,” PJM’s Steve Herling said.
Germany has experienced one grid-related outage since 1990, and consumers have resisted suggestions to reduce costs that might increase that risk.
Changes
PJM’s cost sensitivity might shift, if staff have anything to say about it. Vince Duane, PJM’s senior vice president for law, compliance and external affairs, said the RTO needs “an honest discussion” about maintaining reliability at least cost to reflect consumers’ actual interests.
“I hope what will evolve is a dialogue in the very near term that will examine that,” he said. Last week, PJM released the summary of a study that showed the RTO could face outages under extreme winter weather, gas pipeline disruptions and “escalated” resource retirements. Officials said the findings support the need to compensate generators based on their “fuel security.” (See related story, PJM Begins Campaign for ‘Fuel Security’ Payments.)
The transition might not be easy. Duane noted that one German representative said the “broader value proposition of decarbonization” is a “cleaner, quieter, more elegant world.”
“Those are three terms that have never been used to describe Americans, so we have our work cut out for us,” he said.
More to Come
While Germany has made major strides in its transition, there is still a ways to go, panelists said.
Both American and German panelists noted that surcharges on customer bills for things like system upgrades and resource subsidies are politically expedient but dull market signals that might help consumers reduce demand.
“There’s nothing greener than the electron you don’t produce,” Duane said. “At the end of the day, getting consumers to see prices and respond to prices … has to be a critical policy objective. … At least in this country, we still have a tremendous amount of dumb, discretionary load that could be curtailed, but … people don’t see a reason economically to do that, and they won’t see that reason if a lot of the electricity bill is basically tax.”
Thorsten Herdan, director-general for energy policy, heating and efficiency in the Ministry for Economic Affairs and Energy, noted in his opening remarks that the country’s energy transition focused on electricity — ignoring 80% of the country’s energy use.
“The building stock has not been addressed that much that we can meet our targets for the building sector,” he said. “We have just forgotten the transport sector. That was one of our biggest mistakes. … What are we going to do with what’s left? Are we going to electrify it? I have my doubts.”
CHICAGO — PJM CEO Andy Ott opened his remarks at last week’s annual meeting of the Organization of PJM States Inc. (OPSI) with a sports metaphor to describe the wide array of discussions that were to follow.
While there are many teams trying to achieve many goals on that field, Ott expressed willingness during the two-day meeting to consider rule changes that could redefine how they interact.
He also said there are “many ways to skin the cat” in addition to the capacity market to ensure long-term resource availability. PJM and its stakeholders have been working on a market overhaul for the past two years and smaller reforms for many years prior to that.
PJM staff have proposed adding a second phase to the annual Base Residual Auction to mitigate the impacts of subsidies on resources along with a “resource-specific carve-out” that would allow states to remove from the auction qualifying resources and procurement obligations for a corresponding amount of load. Ott’s comments suggested a willingness to reconsider American Municipal Power’s desire to emphasize bilateral contracting over procurement in the BRA. In August 2016, AMP led a coalition with other municipal utilities and cooperatives calling for a “holistic assessment” of the Reliability Pricing Model. (See Co-ops, Munis Call for Reset of PJM Capacity Model.)
A capacity market is “the most efficient way,” Ott said, but he added “frankly, if we need to evolve that … that’s doable.”
State Objectives
Ott’s openness to change was a recognition of state regulators’ frustration with the RTO. In the meeting’s first panel discussion, several regulators reiterated their intent to continue pursuing generation subsidies and other preferential policies despite opposition from pure-market advocates.
“I think I can say without question that our citizens do benefit greatly from PJM and the wholesale markets,” Maryland Public Service Commissioner Michael Richard said. “However, if we can’t find ways to adequately and fairly accommodate state policies, I’m concerned that [FERC] Commissioner [Cheryl] LaFleur may be right, and states will feel the necessity to effectively reregulate in defense of these state policies. We hope that that’s not the case and the direction that we go in.”
LaFleur expressed her concern in June, when she dissented in FERC’s 3-2 ruling requiring PJM to revamp its minimum offer price rule (MOPR) to address capacity price suppression from rising state subsidies for renewable and nuclear power. The commission initiated a “paper hearing” on the issue (EL18-178). (See FERC Orders PJM Capacity Market Revamp.)
Joe Fiordaliso, president of the New Jersey Board of Public Utilities, said his state is on a “clean-energy crusade” and working toward the largest statewide offshore wind solicitation in the country. “We must never forget the economic impact of clean energy,” he said.
Illinois Commerce Commissioner John Rosales forcefully defended his state’s zero-emission credit subsidy for several in-state nuclear plants, arguing that Illinoisans deserve capacity credit for the program because they pay for it.
“That has to be recognized, and when it’s not, I get a little angry. … That has to be accommodated by PJM,” he said.
The rhetoric got even more heated after Direct Energy’s Marji Philips criticized the vying state policies as “kids in a sandbox” kicking sand at each other.
“Are you ready to go back and tell your consumers you’re pulling out of PJM? … Because that’s what you’re doing. You’re destroying the … integrity of the market if you all do the things you want to do,” she said.
“We will kick sand in your face. I’m just being honest. We’re paying for it,” Rosales responded.
He said he felt the capacity revamp discussions at PJM were a “punitive” response to Illinois’ ZEC rule and designed so that Illinois is “going to take the hit” as an example for other states to deter them from “doing the same thing.”
He noted the state is “in a better position to negotiate in good faith” following the decision in September of the 7th U.S. Circuit Court of Appeals to uphold Illinois’ law. (See 7th Circuit Upholds Ill. ZEC Program.)
The other regulators on the panel attempted to strike a conciliatory tone.
“I’m not trying to destroy anything. I’m trying to build a better foundation,” Fiordaliso said.
“I don’t think it’s mutually exclusive,” said Richard, who became OPSI’s president for the next year. “We’re willing to pay for the [renewable energy credits]. We’re willing to pay additionally. There’s a strong interest [among Maryland residents] in helping the environment.”
Ohio Public Utilities Commissioner Beth Trombold touted the state’s utilization of its natural gas supplies and made it clear that the state was no longer seeking to protect its coal-fired generation. FERC ruled in April 2016 that it would scrutinize power purchase agreements between affiliates like ones requested in Ohio by American Electric Power and FirstEnergy under the Edgar affiliate abuse test. The companies subsequently scaled back their PPA requests to the commission.
“We’ve faced that ourselves, and we’ve moved in a different direction. We’re a big fan of competitive markets and we want to see that preserved,” Trombold said, noting her commission’s recent PowerForward initiative to give utilities “a sense of the framework we’re interested in seeing” them follow in making filings.
Pennsylvania Public Utility Commission Vice Chair Andrew Place noted that the Keystone State ranks 23rd in renewable generation.
“That speaks to my realization that we are not where we should be,” he said. Place also criticized PJM’s rules on how demand response is handled.
“It is vital that these programs be incorporated into PJM’s forecasts,” he said. “More recently, PJM’s accommodation of cost-effective, summer-DR, supply-side markets has come up, in my consideration, short of the mark.”
His comments were in reference to PJM stakeholders’ approval at the October Markets and Reliability Committee meeting to “better value” summer-only DR by allowing the resources’ value to impact the load forecast as an alternative to participating as a supply-side resource in capacity auctions. To avoid double counting, resources that take the peak-shaving alternative wouldn’t be eligible to participate as either a DR resource or price-responsive demand in the same year. (See “Summer-only Demand Response,” PJM MRC/MC Briefs: Oct. 25, 2018.)
Environmental or Economic Interests?
Direct Energy’s Philips asked regulators whether their states’ policies were driven solely by environmental concerns or were also influenced by economic interests.
“Would a carbon price make you happy, or would you still want that [renewable] development in your state?” she asked.
Fiordaliso noted New Jersey is re-entering the Regional Greenhouse Gas Initiative (RGGI) and that “carbon pricing is certainly a part of the portfolio.” Maryland is also a RGGI member, Richard said, “and yes, Maryland would like to develop as many of those resources in state as possible.”
“Keeping these policies with policymakers and with the states; I think that’s the appropriate place,” he added. “I get a little nervous with a discussion that somehow PJM might adopt and create its own carbon-pricing regime.”
Trombold deflected the question, saying Ohio’s legislature sets its energy policies. Michigan Public Service Commissioner Rachael Eubanks noted that carbon is not mentioned at all in her state’s legislation on advancing “renewable energy technologies and the corresponding benefits that come out of that, including economic benefits.”
“I would think that it would have to be a national discussion,” Rosales said. It would be “unfair” to have a carbon price implemented inconsistently across the RTOs, he said.
“The overarching goal is the environment,” said Place, who said earlier it’s his commission’s “social obligation” to either join RGGI or “see that [carbon pricing] comes about.” However, he also noted a Pennsylvania law passed in 2017 that supported in-state solar production.
“I’m not always a fan of being parochial, but at the same time, Pennsylvania was leaving a lot of tax benefit [and] federal financial support on the table, and other states were gobbling that pie. Probably sound policy, but one that in some ways does strike me as discordant,” he said.
In a subsequent panel, PJM stakeholders hashed out concerns about the current state of the capacity market revamp. The Sierra Club’s Casey Roberts said the RTO’s proposal is among those that “on their face” appear to accommodate state preferences but actually do not.
“It increases the costs to states to pursue their policies by making them pay twice,” she said, calling payments made to units whose bids are pushed out of clearing by state-supported resources “the consolation prize” and “icing on the already fattening cake that consumers probably don’t want to consume.”
Craig Glazer, PJM’s vice president of federal government policy, expressed concern over the impact of state policies on an interconnected grid.
“What if this had been a subsidy for coal from West Virginia? Would Exelon and Sierra Club be arguing states’ rights?” he asked. “If you start having one state’s policy choice … affecting every other state, your legislature may not have agreed to that policy, but you are in fact subsidizing that policy. … It’s really at the end of the day an interstate commerce challenge.”
Andrew Novotny, Calpine’s executive vice president of commercial operations, said PJM’s proposal is intended to ensure that states pay in total what they already pay today.
“That’s why we support it. States won’t be paying twice under that. They’ll just be basically paying what they are today with the sliver of side payments [for subsidies]. And if it’s not working out like that in the math, I’m sure the generator community is more than open to some sort of compromise to make sure it does work like that.”
Other Hot Topics
The meeting also covered several other hot topics, including how the evolving definition of “grid resilience” might impact wholesale markets, whether PJM’s energy market needs to be revamped and the state of the RTO’s governance.
Panelists debated how people will respond in emergencies to either share resources or horde them. Daniel Rogier, AEP’s vice president of transmission asset strategy and policy, explained his company’s “no regrets” focus for making system upgrades that have little or no downside, such as replacing wooden poles with steel ones.
Virginia State Corporation Commissioner Mark Christie noted the difficulty with making state desires known at FERC, which has switched chairs four times in less than two years.
“You express it to the chair, and the next week there’s another chair,” he said.
On energy market changes, PJM’s Stu Bresler assured attendees the RTO is “not trying to go energy-only” and therefore doesn’t need spot prices “as high as ERCOT does.” His fellow panelists urged that any changes need to come with additional transparency and granularity that allow the market mechanisms to work without administrative involvement.
Panelists on PJM governance agreed that any changes on committee structure or sector membership and vote weighting will be difficult to implement.
But Gabel Associates’ Mike Borgatti, who chairs PJM’s Members Committee, acknowledged states’ concerns about their ability to get involved.
“It’s unequivocal that what we’re doing now is not capturing enough of your input,” he said. “Figuring out how to balance that dichotomy is a two-way street.”
If you’re as old as me you may remember the movie “Body Heat” from 1981. That last scene with Kathleen Turner on an exotic island beach somewhere.[1] Yeah, you know what I’m talking about.[2]
That brings us to the GreenHat Energy debacle, with the stakeholder tab running around $185 million.[3]
Folks seem to think the GreenHat principals lost everything as their PJM financial transmission rights portfolio deteriorated in value. Bloomberg’s headline: “Ex-JPMorgan Traders Lost Millions on Bad Bets in Power Market.”[4]
I don’t think so. I suspect the GreenHat principals, Andrew Kittell, John Bartholomew and Kevin Ziegenhorn, are sipping blender drinks on island beaches just like Kathleen Turner.[5]
Kathleen Turner in the movie “Body Heat”
The Stage
But first let’s set the stage. Two of the GreenHat principals, Kittell and Bartholomew,[6] are fresh off the JPMorgan market manipulation in California from 2010 to 2012 for which JPMorgan “agrees to pay a civil penalty of $285,000,000 [and] agrees to disgorge alleged unjust profits of $125,000,000.”[7] Kittell and Bartholomew themselves paid nothing.
As recounted in a detailed RTO Insider story, they set up shop in 2014 as GreenHat Energy.[8]
“Green hat” in Chinese basically means someone is getting screwed. So at least they had a sense of humor.
Over several years, they accumulate the largest FTR portfolio in PJM history — 890 million MWh — backed by only $600,000 in collateral.
It isn’t clear that PJM connected the dots of Kittell and Bartholomew to the JPMorgan market manipulation, though the connection was hiding in plain sight in FERC’s eLibrary via a word search on “Andrew Kittell” or “John Bartholomew.”
How the Scheme Works
The scheme here relied on the minimal collateral requirement to hold hundreds of millions of dollars in FTR positions. All that has to happen for GreenHat to make money is for positions to change in value over time — as of course they will — and for GreenHat to sell “in the money” positions to third parties. GreenHat would prefer that the overall value of its portfolio increase over time, but that isn’t necessary for GreenHat to make money because GreenHat can sell positions with value, and default on the rest. Indeed, GreenHat would want to buy every possible FTR with zero incremental collateral requirement, regardless of whether it expected those FTRs to make money.
Let me give you an example that is so simple even I can understand it. Let’s say PurpleHat Energy joins PJM and puts up $600,000 credit. PurpleHat buys long-term FTRs with no additional credit requirement: let’s say FTR 1 from source A to sink B for $10, and say FTR 2 from source C to sink D for $6.
As time goes on, FTR 1 decreases in value from $10 to $7, and FTR 2 increases in value from $6 to $8. PurpleHat bundles up FTR 2 and thousands of other FTRs that have increased in value (i.e., “in the money”) and goes looking for a buyer of these “winners.” Now the buyer looks at FTR 2, for example, and is thinking that if the current $8 value is maintained to settlement, PJM will pay me $8. Of course the buyer has to discount that $8 for the time value of money, risk of value change (could be up, down), etc. So the buyer agrees to pay PurpleHat, say, $7. Notice that PurpleHat has made $1 on FTR 2 ($7 revenue minus $6 cost). Multiply that by thousands of other FTRs and their megawatt-hour quantities and you get to real money real fast.
Now remember PurpleHat is selling winners for cash to third parties and will default on the losers. So PurpleHat can make wads of money even if its overall portfolio of winners and losers goes down in value. Got it?
The Collateral That Wasn’t
Beyond this big picture, here’s a remarkable part of the story: As the GreenHat portfolio deteriorated in value, and some FTR participants raised red flags with PJM,[9] PJM asked GreenHat for more collateral.
GreenHat purported to provide that, in June 2017, in the form of pledging $62 million in future revenue from FTR sales agreements that GreenHat had with a third party, which we now know is Shell Energy North America[10] (“Pledge Agreement”). Here is how PJM described it: “Mr. Kittell worked with PJM to establish a dedicated depository account and represented that GreenHat would request the third party to deposit the revenues from the bilateral contracts into a bank account that PJM had access to and from which PJM would execute automated clearing house withdrawals to cover net losses that accumulated in GreenHat’s PJM account.”[11]
Now, one might think, wouldn’t PJM verify with Shell that Shell hadn’t already given GreenHat some or all of that $62 million (assuming that $62 million is a real number)? Well, PJM did ask GreenHat for permission to check with Shell about that $62 million, and GreenHat said … no.[12]
Now, one might think, that’s that: PJM would tell GreenHat to come up with something better than a Nigerian prince story for $62 million. Instead, PJM went ahead with the Pledge Agreement,[13] saying it had no choice,[14] and GreenHat went on to more than double the size of its FTR position.[15]
And, as fate would have it, GreenHat had already pocketed whatever was owed by Shell (not $62 million, but perhaps $7 million — more on that next).[16] Uh oh.
The $62 Million That Wasn’t
There’s one more part of the story to tell here. You’ve probably assumed, like I did, that there had to be something to the $62 million claim that GreenHat made to PJM. But maybe that ain’t so. Maybe there never was any $62 million — not at the time of the FTR sale to Shell, or ever.
Analysis of the GreenHat positions suggests they were purchased at a cost of approximately $19 million when GreenHat acquired them (with minimal collateral) and valued in the range of $25 million when GreenHat sold them to Shell. It seems what GreenHat entered into the PJM eFTR system was just made up.[17]
Per Queen in “Bohemian Rhapsody”: “Is this just fantasy?” And here the answer seems “yes.”
What Now?
What’s to be done now? FERC Enforcement should be all over this if it isn’t already. The penalties for market manipulation can be substantial as the JPMorgan order shows.[18] And PJM should vigorously pursue civil action, such as the one initiated in Texas.
Lesson for the Future
Lesson for the future: All RTOs should carefully review all their credit requirements for everything — with experts in credit — just in case Kittell and Bartholomew, or others like them, are coming their way.
P.S.: The GreenHat experience is not an indictment of energy markets in general, or FTRs in particular. It is a cautionary tale of faulty credit policy and oversight.
As early as April 2016, at least one FTR market participant was warning PJM about a 100 million MWh FTR position with minimal collateral, what DC Energy called the “Illustrative Portfolio” (yes, GreenHat’s). https://elibrary.ferc.gov/idmws/common/OpenNat.asp?fileID=1493734. ↑
“PJM Interconnection, L.L.C. … Verified Rule 202 Petition,” District Court of Harris County, Texas, Cause No. 201869829-7, filed Oct. 1, 2018. ↑
“PJM asked Mr. Kittell for permission to contact the counterparty to the bilateral trades regarding the contractual arrangement with GreenHat, and Mr. Kittell denied PJM’s request and specifically asked PJM not to contact the counterparty.” https://elibrary-backup.ferc.gov/idmws/common/opennat.asp?fileID=14995137 (page 4). ↑
The email trail we have in the FERC filings has PJM asking for more support from GreenHat and ultimately sending an email on April 19, 2017, requesting a log of every payment GreenHat had received from Shell. But from there the paper trail goes cold: PJM doesn’t provide any response from GreenHat. https://elibrary-backup.ferc.gov/idmws/common/opennat.asp?fileID=14995137 (Appendix B, second page).Nor does it appear PJM questioned why Shell would pay GreenHat $62 million for positions actually worth a fraction of that amount (as discussed later). ↑
“To avoid a claim of interference with GreenHat’s contractual counterparty and to allow GreenHat the ability to sell down its portfolio, PJM had no choice but to comply with this request [that PJM not contact Shell].” https://elibrary-backup.ferc.gov/idmws/common/opennat.asp?fileID=14995137 (page 4).This is puzzling. PJM had at least colorable Tariff authority to require meaningful collateral or other protection (if not as a condition to maintain existing positions, surely as a condition to expand those positions): “PJMSettlement may select participants for review on a random basis and/or based on identified risk factors such as, but not limited to, the PJM markets in which the participant is transacting, the magnitude of the participant’s transactions in the PJM markets or the volume of the participant’s open positions in the PJM markets. Those participants notified by PJMSettlement that they have been selected for review shall, upon 14 calendar days’ notice, provide a copy of their current governing risk control policies, procedures and controls applicable to their PJM market activities and shall also provide such further information or documentation pertaining to the participants’ activities in the PJM markets as PJMSettlement may reasonably request. … Each selected participant’s continued eligibility to participate in the PJM markets is conditioned upon PJMSettlement notifying the participant of successful completion of PJMSettlement’s verification of the participant’s risk management policies, practices and procedures, as discussed herein.” PJM Tariff Attachment Q, Section I.B (emphasis added).PJM seemed to rely on Attachment Q, Section II.D.2 (PJM has the right to “require additional collateral as may be deemed reasonably necessary to support current market activity.”), but this section appears applicable only to an “unsecured credit allowance,” which is not what GreenHat apparently had. ↑
GreenHat had a portfolio position of about 375 million MWh in mid-June 2017. The Pledge Agreement was entered into late June 2017. GreenHat went on to increase its position to 890 million MWh. https://elibrary.ferc.gov/idmws/common/OpenNat.asp?fileID=14937343 (Figure 1, page 9).It is not clear how this more than doubling of the GreenHat position comports with PJM’s statement, quoted in the preceding footnote, that PJM was motivated to go forward with the Pledge Agreement to “allow GreenHat the ability to sell down its portfolio” (emphasis added). ↑
“PJM specifically asked Mr. Kittell if the counterparty had paid GreenHat any of the money due to GreenHat under their bilateral trade agreements. GreenHat never informed PJM that the counterparty had paid any money on that contract. Instead, Mr. Kittell forwarded PJM documents indicating money that it claimed the counterparty owed to GreenHat under their contract that would flow to PJM under the Pledge Agreement. It wasn’t until June 2018 that PJM learned from Mr. Kittell that GreenHat sent two invoices with a “Final Purchase Price” due from the counterparty to GreenHat under two separate FTR bilateral agreements between the two parties — well before GreenHat commenced discussions with PJM regarding the Pledge Agreement, and that the counterparty paid GreenHat all of the money the counterparty believes was due to GreenHat under those bilateral agreements.” https://elibrary-backup.ferc.gov/idmws/common/opennat.asp?fileID=14995137 (pages 4-5, emphasis added). ↑
How is such a thing possible? GreenHat could have used the PJM eFTR system so as to make it appear as if Shell owed GreenHat an amount that far exceeded the actual value of the positions. There is a field in the eFTR system, which PJM does not use in settlement, that purports to offer market participants the ability to enter bilateral contract transaction prices. The GreenHat/Shell transacted FTRs had entered prices in this field that did in fact add up to at least $62 million, which GreenHat apparently offered to PJM as proof that it had receivables to pledge to PJM. But use of this field is not customary for bilateral transactions in the eFTR system (most market participants leave this field blank or enter 0). In other words, GreenHat could have entered 62 cents or $620 trillion with no economic significance (which may explain why Shell would not have cared what GreenHat entered). The actual transaction prices between GreenHat and Shell would be governed by the contracts entered into by the parties, not by what was entered into eFTR. The GreenHat invoices in 2016-2017 for “Final Purchase Prices” of $5.2 million and $1.5 million appear to reflect the economic substance of the FTR sales. ↑
PJM is trying to keep $550,000 in collateral of a GreenHat affiliate in PJM Interconnection, L.L.C., Docket No. ER18-1972-000. $550,000 is peanuts. PJM’s efforts should be on civil action and on FERC Enforcement. ↑
