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.”
LITTLE ROCK, Ark. — SPP directors, members, staff and other stakeholders took time out last week from the normal board week activities to honor two directors who predate the organization’s RTO status.
The RTO treated Jim Eckelberger, who stepped down in April after 14 years as the Board of Directors’ chairman, and Harry Skilton, vice chair for 14 years, to a catered farm-to-table dinner the night before the Oct. 30 board meeting.
Staff shared a video of family, friends and stakeholders sharing their favorite anecdotes about the two men. Both were presented with plaques topped by — what else? — replicas of transmission towers.
Eckelberger and Skilton are the last remaining members of SPP’s original board, which was created in 2000. FERC didn’t recognize SPP as an RTO until 2004.
Since then, SPP has expanded its footprint with the addition of Nebraska utilities and the Integrated System, and by offering reliability coordination (RC) services to Western Interconnection entities. The RTO has also become one of the lowest-cost grid operators by creating day-ahead and financial transmission rights markets and investing billions in transmission infrastructure.
Eckelberger, who takes great pride in SPP’s cost of service, pointed to an LMP contour map of the footprint, dominated by the cool blue denoting prices in the $20 to 30/MWh range, as an example of the RTO’s effectiveness.
“SPP greatly appreciates the 18 years Jim and Harry dedicated to SPP,” CEO Nick Brown said. “They have made extraordinary contributions to our company and were instrumental in transforming SPP into the regional transmission organization we are today.”
“Both should be proud of the legacy they have created here for SPP,” said Larry Altenbaumer, who replaced Eckelberger as chairman in April.
“I’m very fortunate to have 18 years at SPP be the capstone of my career,” Skilton said.
Both men are transitioning into emeritus status, effective Jan. 1.
“We’re fortunate they’ll be staying on in this emeritus role, because they have a wealth of experience,” said the Members Committee’s Tom Kent, COO for Nebraska Public Power District.
The Members Committee replaced Eckelberger and Skilton on the board by electing newcomers Susan Certoma and Darcy Ortiz during its annual meeting. The appointments are effective Jan. 1.
Bruce Scherr, who joined the board in January 2016, was also re-elected.
Certoma is president of Enterprise Engineering, which provides software and consulting to financial firms. She previously held technology-related positions at Wachovia Bank, Goldman Sachs, Merrill Lynch and Lehman Brothers during 30 years in the finance field. Certoma holds a bachelor’s degree in management and economics and an MBA from St. John’s University.
Ortiz is Intel’s vice president and general manager of corporate services. She previously led the global team responsible for Intel’s IT operations and services and served in several CIO positions. She has a bachelor’s degree in business administration from the University of New Mexico and an MBA from the University of California, Berkeley.
Brown said the new members’ technology backgrounds will be invaluable to SPP.
“Much of our continued success now hinges on effective management of data and technology infrastructure and our approach to cybersecurity,” he said in a statement.
The committee also elected seven representatives to three-year terms on the committee, with “the narrowest of unanimous margins,” Altenbaumer joked.
The representatives are Kent for State Power Agencies; Blake Mertens (Empire District) and Kevin Noblet (Evergy) for Investor-Owned Utilities; Jason Atwood (Northeast Texas Electric Cooperative) and Mike Wise (Golden Spread Electric Cooperative) for Cooperatives; Kevin Smith (Tenaska Power Services) for Independent Power Producers/Marketers; and Jody Sundsted (Western Area Power Administration – Upper Great Plains) for Federal Power Marketing Agencies.
Mertens is the only newcomer; everyone else was re-elected.
Altenbaumer Tweaks New Governance Schedule
Altenbaumer continues to tinker with the board’s meeting schedule as he enters his first full year as chairman, saying he wants to “elevate the work of the board and members to focus on those things that are strategically important.” (See SPP Strategic Planning Committee Briefs: Oct. 18, 2018.)
Following feedback from members and the Regional State Committee, Altenbaumer has scheduled a joint session between the board and RSC on the day the state regulators normally meet (the day before the board’s quarterly meeting). That time will be used for joint informational and background presentations to the directors, members and RSC.
“It’s an opportunity to become more efficient,” Altenbaumer said. “Many presentations given to the RSC turn out to be warmups for the same presentations to the board the next day.”
Altenbaumer has left slots in the RSC and board meetings for executive sessions, but he promised “anything that relates to decisions will be addressed during the typical [open] board meeting.”
Addressing stakeholder concerns that the changes could reduce transparency, Altenbaumer said keeping discussions from public view is “by far the last thing intended from this.”
“If any of you ever feel these things are trending in the wrong direction, as far as engagement and transparency, bring it to my attention,” he said.
Given a chance to respond publicly to Altenbaumer’s comments, no one did.
As proof of how governance will be handled in the future, Altenbaumer noted the board’s only approval item was the consent agenda.
“That speaks to the collaborative process,” he said. “This is a desire to try and improve the overall governance.”
Two days later, SPP moved its December board meeting, which has traditionally been used to approve the budget, from Little Rock to the more accessible Dallas/Fort Worth International Airport. The meeting has also been shortened by two hours; next year, it will likely become a conference call.
Keith Collins, executive director of SPP’s Market Monitoring Unit, clarified comments he made during recent governance meetings that raised stakeholder concerns about the MMU’s involvement in generator retirement decisions. (See Stakeholders Push Back Against SPP Retirement Changes.)
At October’s Markets and Operations Policy Committee and Strategic Planning Committee meetings, some stakeholders pushed back against the possibility of the MMU intervening in regulatory proceedings. Collins said the MMU would only raise concerns in instances of physical withholding or other market power issues.
“The SPP Tariff is very clear,” he said. “Physical withholding and market power are under the MMU’s purview.”
“The MMU has an obligation to investigate and review those issues,” said Director Joshua W. Martin III, who chairs the Oversight Committee. The MMU reports to Martin’s committee.
Collins said the MMU has always used available data when it reviews generator retirement requests, and that the MOPC discussion was an attempt to collect data from market participants to improve its analysis.
He noted the Tariff is unclear as what the MMU should do if it identifies physical withholding or market power.
“Our responsibility rests with FERC,” Collins said. “To the extent we identify market power of physical withholding, we would have to raise that issue with FERC, unless the protocols or the Tariff [are] clarified as to what steps should be taken.”
“The Oversight Committee has reviewed this issue, and we’re comfortable with where it is right now,” Martin said.
SPP staff have said they will provide the MOPC and the board draft Tariff revisions for generator retirement procedures in January.
SPP-MISO Operating Procedures not yet Documented
Brown said during his president’s report that it is “untenable” that SPP and MISO “end up in situations where our operators are confused,” as happened in January’s “Big Chill” event.
The two RTOs have increased their coordination across their seam since the Jan. 17 event, when severe cold weather and generation shortfalls in MISO South led MISO to exceed its regional dispatch limit on transfers between its northern and southern footprints across SPP’s system. MISO made emergency energy purchases from Southern Co. before operations returned to normal.
Brown recalled that shortly after the event, he had told the board that one of his top priorities for the year was to reach an agreement with MISO on “exact operating procedures.”
“I was hoping to report we have signed documents for this meeting, but we don’t,” Brown said.
He was able to share with directors and members a pamphlet that says SPP members receive $1.7 billion in annual benefits, an 11-1 benefit-cost ratio. The document notes the Integrated Marketplace has produced more than $2 billion in savings since going online in 2014 and references a study that indicates every dollar SPP spends on transmission investment returns $3.50 in benefits.
“I would have no problem standing before any regulatory committee and defending these numbers,” Brown said.
Western RC Services to Net $3.4M
Operations Vice President Bruce Rew said SPP’s RC contracts with Western Interconnection entities will result in $3.4 million in net income through 2024. (See CAISO RC Wins Most of the West.)
SPP expects to earn $28.4 million in revenue over the life of the five-year contracts, which are effective in January 2020. However, adding up to 20 staffers in Little Rock to handle the new responsibilities will eat into much of that revenue.
Under the contract’s terms, the Western entities will pay an initial 5.5 cents/MWh. Annual extensions will begin in 2025, and mutual withdrawal provisions are included.
Smaller entities may yet participate in SPP’s RC services, Rew said. Later entities would be evaluated on a case-by-case basis.
Consent Agenda’s Approval Adds, Deletes Members
The board’s consent agenda included changes to the membership agreement that would clear the way for Mor-Gran-Sou Electric Cooperative to become the newest SPP member.
The Corporate Governance Committee approved membership agreement amendments for the North Dakota co-op similar to changes that facilitated the membership of Basin Electric Power Cooperative and its members as part of the Integrated System’s integration. Mor-Gran-Sou, which is embedded within the Integrated System, intends to join SPP as a transmission owner.
The CGC also recommended Cielo Wind Power’s membership be terminated immediately for failing to keep up with its membership dues and repayment agreements. SPP said Cielo in January stopped responding to the RTO’s outreach efforts and ignored a March demand letter.
The Austin, Texas-based company’s delinquency dates back to 2016. It owes $18,000 and interest.
The consent agenda also included staff’s recommendation to revise the SPP-MISO Coordinated System Plan. (See “MOPC Approves Changes to Joint Model with MISO,” SPP MOPC Briefs: Oct. 16-17, 2018). Also on the agenda were the Finance Committee’s 2019 operating plan, updates to the 2019 Integrated Transmission Planning assessment’s scope, the Market Working Group’s annual violation relaxation limits analysis, and nine revision requests:
MWG RR266: Substitutes “interest” for “ownership” in language modeling joint-owned units as single resources, recognizing that “ownership” doesn’t capture stakeholder intent that power purchase agreements and other non-ownership interests be included.
MWG RR288: Allows non-dispatchable variable energy resources converting to dispatchable status to use control statuses not originally available to them. SPP’s control statuses are: offline (the resource is not operating); non-regulating (online and capable of following a dispatch instruction or contingency reserve deployment but not eligible to clear regulation service); regulating (online and capable of following dispatch or contingency reserve instruction, and regulation deployment); and manual (online but not able to follow dispatch; e.g., start-up, shutdown, testing, etc.).
MWG RR316: Updates the multi-configuration (combined cycle) resource market design by adding two additional commitment parameters: group minimum down time and plant minimum down time. Also removes sync-to-min and min-to-off times from the submitted minimum down time or group minimum down time when the resource transitions between operational configurations. The current design only allows individual registered configurations to submit a minimum down time.
MWG RR323: Defines batteries as electric storage resources (ESRs), capable of being dispatched and participating in price formation. Excluded as ESRs are those resources that are either contractually barred or physically incapable of injecting energy back onto the grid because of their design or configuration. Also creates a new registration type, “market storage resource,” to be used only by ESRs.
MWG RR332: Corrects protocol calculations from designs implemented in RR200 (design change for bilateral settlement schedules (BSS) and over-collected losses (OCL) distribution) and RR235 (correction to RR200) necessary to accurately distribute OCLs and ensure BSS are receiving their correct OCL. The change ensures corrected resettlements back to the original May 1, 2018, release date.
ORWG RR318: Changes the contingency reserve requirement calculation to allow the use of the “most severe single contingency” as the basis of the minimum contingency reserve requirement on an hourly basis. SPP said the revision allows it to more accurately and reliably set the reserve requirement.
RTWG RR305: Updates Tariff language following modifications to the aggregate facilities study process by removing the requirement to file a service agreement before modeling new transmission service in the ITP models. Also removes the requirement that SPP issue notifications to construct (NTC) and notifications to construct with conditions (NTC-C) before filing a service agreement. Adds a financial commitment date of four years to the issuance of an NTC or NTC-C.
RTWG RR322: Changes the Tariff and other documents to reflect that the RTO is no longer using U.S. Energy Information Administration data in monthly load forecasts. SPP said the data in the EIA report are not granular enough because they are at the balancing authority level, rather than the local balancing authority level required. In January, the RTO began using forecast data that are available through the NERC system data exchange (SDX) and historical data where forecasts are not available.
RTWG RR325: Revises SPP’s pro forma language for large generator interconnection procedures and large generator interconnection agreements to comply with FERC Order 845.
BALTIMORE — The drafters of the 1935 Federal Power Act could not have imagined modern distributed energy resources, let alone a small network of them that can operate independently of the grid.
FERC Commissioner Cheryl LaFleur addresses the Microgrid 2.0 conference in Baltimore. | International District Energy Association
“The phenomenon that I think FERC confronts and other agencies in Washington confront is that there’s been a lot more technological change than there’s been legislative change for a whole bunch of reasons that are above my pay grade to diagnose,” Commissioner Cheryl LaFleur told attendees of Microgrid 2.0 at the Hyatt Regency Baltimore Inner Harbor last week.
FERC Commissioner Cheryl LaFleur | International District Energy Association
“We’re trying to solve 21st century problems using … a 1930s law.”
How microgrids should be regulated was a central topic at the third annual conference held by the International District Energy Association (IDEA), which advocates for distributed generation, district heating and cooling, and combined heat and power.
Christopher Berendt, Drinker Biddle & Reath | International District Energy Association
“The reason we’re here talking about this today, probably more than anything else, is that consumer demand is driving us, and that we’re seeing more and more people say, ‘We want to see mixed-use, multi-customer microgrids because we want the variety of benefits that can come out of them,’” Christopher Berendt, counsel to IDEA’s Microgrid Resources Coalition, said during a panel on market design and policies.
Regulatory risk, he said, “acts kind of like repellant to private capital.”
“There is more capital waiting to flow into microgrid investment right now [that] you would not believe,” said Berendt, a partner with Drinker Biddle & Reath. “There is more capital chasing fewer good projects, and what is really needed to unlock those loads of capital and get more good steel in the ground is not the desire to deploy it, but the regulatory frameworks that support project financing.”
Without any direction from Congress, however, regulators must work with what they have. During her luncheon keynote speech, LaFleur pointed to the complications of DER aggregation, which the commission has been working on for nearly two years. (See FERC Rule Would Boost Energy Storage, DER.)
“It seems quite clear that distributed resources can be aggregated and bid into the market and contribute great value. But since they’re, in many cases, behind the meter, what do the states figure out? Who gets the first bite of the value?” LaFleur asked. “How are we going to figure out who pays what to whom in a sensible way? I think our staff has made a lot of progress in thinking about it. I think it can be worked through, but it’s a little more complicated than some of the … issues we usually deal with because of the number of different uses, and because although it acts wholesale when we see it in the markets, it’s actually at the distribution level.”
Dan Dobbs, Anbaric Development Partners | International District Energy Association
The industry also faces challenges at the state and local levels over siting rights of way and whether microgrids are defined as public utilities. “One thing all jurisdictions in this country have in common is that they’re not set up for microgrids,” Berendt said
Dan Dobbs, vice president of distributed energy for Anbaric Development Partners, pointed to New York’s Value of Distributed Energy Resources tariff as “a start.” (See NYPSC Takes Subway into Value Stack.)
“It’s not perfect, but it’s a good attempt at getting that value,” he said. But “you really need to be able to value power that comes in and goes out equally. That’s at the retail level, and you need to be able to do that similarly at the wholesale level when you are aggregating resources.”
FERC last week allowed GridLiance High Plains to begin rate recovery Nov. 1 for its facilities in the Oklahoma Panhandle but set the company’s proposed annual transmission revenue requirement subject to refund and settlement judge procedures (ER18-2358).
The Oct. 31 order rejected requests from SPP transmission owners to reject the filing or suspend rate recovery.
SPP placed the facilities in Southwestern Public Service’s transmission pricing zone, Zone 11. The RTO said in its August filing that GridLiance’s ATRR and facilities were not large enough to warrant their own pricing zone, and that they were also interconnected solely with Zone 11 facilities.
Tri-County service territory | Tri-County Elec. Co-op
It said the addition of the GridLiance assets will increase Zone 11’s ATRR of $112 million by 6.9%. Network integration transmission service charges will rise 2.8% if the ATRR of transmission facilities whose costs are recovered under Schedule 11 (Wholesale Distribution Service) is included, the RTO said.
More than a dozen SPP TOs and cooperatives and the Texas Public Utility Commission protested SPP’s filing, arguing that the RTO did not explain how upgrades GridLiance made to the Tri-County assets benefit existing Zone 11 customers and questioning how FERC could determine the additional costs were fair without analyzing the benefits.
Xcel Energy complained that GridLiance constructed more than $50 million of facilities outside the SPP regional transmission planning process even though the Tri-County load has decreased by at least 23 MW since 2016.
GridLiance said its planned and constructed upgrades address outages from ice and wind storms that resulted from a non-networked system.
Brett Hooton, president of GridLiance High Plains, said he was pleased FERC denied requests to reject the filing or suspend rate recovery.
“We look forward to demonstrating why wholesale loads are entitled to enjoy comparable reliability as the load served by the dominate transmission owners within SPP and how our reliability improvement upgrades meet that goal,” he told RTO Insider.
The commission also accepted revisions to SPP’s bylaws that clarify the concept of a financial interest. With the Nov. 1 order, SPP employees, directors and their spouses, minor children, and any person for whom they have power of attorney or guardianship rights will be allowed to invest in companies that have a de minimis relationship with the RTO and the electric sector (ER18-2376).
FERC agreed that SPP’s rules, developed before the expansion of its membership and market participation, created barriers in recruiting and retaining directors and employees. The commission said the bylaw revisions should continue “to safeguard SPP’s independence” by prohibiting directors and employees from investing in market participants active in the Integrated Marketplace.
FERC Order 2000 bars grid operators, staff and non-stakeholder directors from holding financial interests in any market participant and require them to maintain independence from “any entity whose economic or commercial interests could be significantly affected by the RTO’s actions or decisions.”
