MISO will not seek an increase in Tariff rates in 2020 despite proposed spending increases.
The RTO projects it will spend about $368 million in 2020, an 8.3% increase from 2019, with $337.7 million in operating expenses and $30.4 million in capital expenses. But it will again seek a 41-cent/MWh Tariff rate from customers, the same as last year and just a penny more than the 2018 rate.
Since Entergy joined the footprint in 2014, MISO electricity use has remained at 740 to 750 TWh annually.
MISO projects its ongoing market platform replacement project will account for $12.7 million of operating expenses and $12.3 million of capital expenses in the upcoming year. It also forecasts base operating expenses will be $264.7 million, up $9.7 million from last year.
MISO CFO Melissa Brown said a host of issues are driving the uptick in spending, including the market platform replacement, facilities upgrades, wage increases and cost increases in computer maintenance and engineering studies.
The Board of Directors’ Audit and Finance Committee voted unanimously to approve the budget proposal during a conference call Tuesday. MISO will seek a final board vote on the budget Dec. 11 during its quarterly Board Week.
ATLANTA — NERC’s ninth annual GridSecCon was the biggest yet, as more than 600 attendees heard talks on drones, insider threats, supply chain risks and other topics. Here’s some of the highlights of the conference, which was organized by NERC’s Electricity Information Sharing and Analysis Center.
Brian Harrell, assistant director of the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency, rallied the attendees, saying critical infrastructure owners must understand their “gaps” to protect against nation-state attacks.
“It’s on the margins, on the folds; it’s where you’re not looking that an adversary … is looking to exploit,” he said. “We should all understand that one day, we will be faced with a security event. Something will happen in our system. Let me ask this very key question: Are you prepared to be overwhelmed, when it’s the fog of war; there’s incomplete information; everyone is yelling on the radio at the same exact time? Maybe there;s blood on the ground. Are we prepared to be overwhelmed?”
Although DHS has moved past the post-9/11 antiterrorism mission on which it was founded, it cannot prevent sabotage of industrial control systems by itself, Harrell said.
“It takes patriots. It takes those with a vested interest in how we leave this country to our children. So I ask as we leave this conference … that you leave with a ‘to-do’ list, with a list of items that we can do to prepare the next generation, promote resilience, protect our critical infrastructure and work for the common good of national security.”
Harrell said he is surprised at how far behind other critical infrastructure sectors are in their cybersecurity measures compared with the electric industry. DHS is urging other sectors to adopt the model of the Electricity Subsector Coordinating Council (ESCC), which includes more than 30 CEOs of investor-owned utilities, public power companies, rural electric cooperatives and industry trade groups.
Because it is led by CEOs, Harrell said, “when we have a robust conversation around the table, and we say, ‘This is the plan; let’s go forward; let’s make things happen,’ it actually happens. Instead, the other model [without CEOs] is, ‘Let me go back to the shop … get concurrence, get some approvals and then we’ll see you next quarter,’” Harrell continued. “That is ineffective. It is slow. It is burdensome.”
Harrell also discussed insider threats, saying, “I am convinced that we have individuals within our companies that have the institutional knowledge as to how to bring us to our knees. They understand the keys to the kingdom. They understand what the crown jewels are.”
Conducting background checks every seven years isn’t enough protection, he said. “Do we have the technology in place to understand what data is leaving our system and going to somebody else’s Gmail?” he asked.
Fanning: AI Key to Defense Against Increasing Threats
Southern Co. CEO Tom Fanning, co-chair of the ESCC, said the rise of machine learning has resulted in an explosion of attacks against utilities and a need for robust artificial intelligence. Fanning said utilities have faced millions of attacks daily, including efforts to position, probe defenses and gain intelligence.
“Heretofore you can imagine a nondescript concrete building on the streets of Beijing, China, with armies of people banging keyboards trying to get in,” he said. “But as machines learn how to attack, we are now into trillions of [attacks] a day, and the success and failure of attack defense will be driven by how good your artificial intelligence is. It’s almost beyond human capability to … understand an attack and how to defend ourselves.”
Fanning said the Cyberspace Solarium Commission, a bipartisan group of members of Congress, former government officials and industry representatives authorized by Congress, will produce a report later this year or in early 2020 that will “reimagine how government and private industry work together” to address cyber threats.
“The concept of [information] sharing will be obviated in the not-too-distant future. Sharing is too slow,” he said. “I think we will consider an effort to join the data-sharing, knowledge-sharing and sharing of insight among and between the intelligence community, the defense community and private industry in a way that we have never seen before.”
Collaborating to Deal with Squirrels and Nation-states
Karen S. Evans, assistant secretary in the Department of Energy’s Office of Cybersecurity, Energy Security and Emergency Response, joked that her responsibilities span from “squirrels to nation-states.”
“My leadership’s greatest fear is when we are responding to a natural disaster, that that is when our country is most vulnerable. And that’s when we would be taken advantage of,” she said.
She said the relationships between industry, DOE and its national laboratories are crucial to protecting the grid. “The only reason why this is going to work is because of the partnerships that we have within the sector,” she said.
Zach Tudor, Idaho National Laboratory’s associate director for national and homeland security, had a similar message. “The reason we can speak with one voice is you’ve built a community of trust,” he told the audience.
Ross Johnson, president of Bridgehead Security Consulting, also stressed the value of collaboration, decrying organizations that have dropped out of industry groups because management didn’t understand the value.
“They’re crazy,” he said. “You don’t learn anything hanging around the office. You learn from meetings like this.”
Tim Conway, technical director for SANS Institute’s ICS and supervisory control and data acquisition programs, suggested utilities participate in NERC’s biennial GridEx to get tested by “surprise” scenarios and work in the off-years on the risks to which they are most vulnerable.
Conway said the industry can sound “schizophrenic.”
“We say these standards are a baseline minimum, indicating we should all be doing more. But because they’re changing so much, you’re not incentivized to do more because you’d be misallocating capital.”
Ben Miller, vice president for professional services and R&D for Dragos, a security firm focused solely on ICS, said, “There’s a difference between incident response planning and readiness.
“And largely what we’ve been testing to date with GridEx, I would say, is largely on the planning side. Being able to measure and understand readiness is a whole different ballgame.
“I do recognize that GridEx does do interdependency testing,” he continued. “I am suggesting from a threat assessment and threat understanding [perspective], we can sometimes close our eyes to the external facing threats that we don’t control because they’re hard to approach. That said, there’s still very realistic … scenarios that [suggest] some level of planning and discussion should happen outside of exercises.”
DER Risks and Benefits
Several speakers mentioned the potential risk from distributed energy resources.
“If we look at … our infrastructure … there’s visibility right at the edge that we don’t have for certain types of cyber issues,” said Ben Blakely, chief security officer for Hydro One. “You can’t manage scenarios that you’re not aware of.
“I’d be curious to see how other folks are doing in that space and also how it would be manifest in a certain scenario that would have impacts on the distribution and transmission system, and ultimately the customer,” he added.
Conway said DERs provide both risks (lower defenses) and potential benefits (the ability to island during disturbances). “We’re in this weird in-between zone right now,” he said.
Jason Stenstrom, Entergy’s director of detection and response, said heightened awareness of cyber risks has also increased the volume of the “noise” with which he must contend.
“Not to say that is bad, because we’re building the culture where people are being aware of all these potential threats, but it can create quite a bit of noise,” he said. “Our CEO … will hear something … and [the question] will come right down to our CIO and right down to me: ‘What are we doing about this?’ It may not even be relevant to our environments.”
Market Systems’ Vulnerability
Blakely was asked how vulnerable the grid would be if the Ontario Independent Electricity System Operator’s market systems were unavailable or corrupted.
“We actually exercised this a few years back in a GridEx scenario,” he responded. “And one of the things we identified was, sure, we understood the criticality of the settlements and markets processes, but we’re not applying the appropriate controls consistent with where the other crown jewels are — at that point in time, the ESP [electronic security perimeter]. So, we actually started to put plans in place to harden that portion of the infrastructure.”
Blakely said Ontario can operate the power system without the market functioning, having a way to process settlements afterward. Still, he said, “It’s absolutely concerning. I don’t think it’s fully explored.”
Kathy Judge, head of U.S. physical security for National Grid, talked about the difference between reliability regulation of the oil and natural gas (ONG) industry and that of the electric grid, which answers to NERC.
“On the ONG side, we have many parents we have to answer to, and they don’t always agree in their approaches,” she said. “They each have their own regulations. … We have TSA [Transportation Security Administration] for pipeline security guidelines; we fall under the Department of Transportation under PHMSA [Pipeline and Hazardous Materials Safety Administration] regulations and DHS for [counterterrorism] standards. We’re under FERC in some situations. Each state regulates us, and then the U.S. Coast Guard [does so] as well. So, you can have a situation one week where you can have three different regulators come to look at the same site. So, not always ideal from an operational perspective.”
The positive: Gas regulations are “much less prescriptive” than NERC’s, Judge said. “We like that.”
Robert Mims joined Southern Co. as director of security for its gas, nuclear, generation and transmission operations, after the company’s acquisition of AGL Resources (now Southern Company Gas) in 2016. He confessed to having “NERC envy” when he was responsible for gas alone.
“I would see my electric peers and see all the resources they had to apply to the same problem that I did. But they’re serving 4.2 million customers with 30,000 employees, and they’ve got a team of 100 cybersecurity people. And I’m dealing with the same circumstances [with fewer resources] … so, it’s a challenge,” he said. “I don’t have regulations; I have pipeline security guidelines that are voluntary. If it takes a regulatory action to get me those resources, I’m all for it. That’s one way of looking at it.”
He recalled the 1965 blackout that led to NERC’s formation and the 2003 outage that caused Congress to authorize mandatory reliability standards for grid operators.
The gas industry knows “we’re one incident away [from mandatory regulations],” he said. “In the meantime, we’re going to keep working together, with a lot of industry collaboration, a lot of partnerships, and just understand our own risk and threats and doing what we think is the right thing for our companies to mitigate those risks.”
Not Sleepless in Idaho Falls
Several of the panel discussions included that hoary question, “What keeps you up at night?” Although the security of 5G technology concerns him, INL’s Tudor insists he sleeps well.
“I like to say, ‘I’m from Idaho Falls and I sleep like a baby, [thanks to] that fresh air and everything else,’” he said. “A lot of us have been here and doing this for a long time, and we’re really getting better. So, yeah, the adversaries are getting more sophisticated, but our community’s growing. We’re learning more, so it makes me hopeful every day. So, I don’t try to take it to bed with me. I just wake up energized to do more the next day.”
ATLANTA — “For the record,” joked Ben Miller, “I cry watching ‘Frozen.’”
Miller was one of five former colleagues who offered sometimes tearful, often funny, tributes to the late Mike Assante during the emotional highlight of GridSecCon 2019 last week.
Assante died July 5 at 48, following a more than 15-year battle with cancer. After serving more than a decade in the Navy and being named Intelligence Officer of the Year for the Pacific Fleet in 1997, Assante became NERC’s first chief security officer after a stint as CSO for American Electric Power. He later worked for Idaho National Laboratory and became director of the SANS Institute’s industrial control systems and supervisory control and data acquisition security training curricula.
The speakers Oct. 23 praised him as a visionary, noting his 2009 letter to stakeholders as NERC CSO that called for a shift to consider potential misuse of cyber assets, not just the loss of them.
“A lot of the things he [did] at NERC, including the letter, including the HILF report — high-impact, low frequency report — created the structure [to] move the ball forward beyond merely regulation,” said Miller, vice president of professional services and R&D for Dragos. One product of that effort was the Electricity Information Sharing and Analysis Center. (“We probably wouldn’t have the E-ISAC without Michael Assante,” NERC CEO Jim Robb told the organization’s board of directors in August.)
But Assante’s greatest gift, speakers said, was his ability to inspire, recalling career pivots they made based on his advice. And his legacy, they said, would be the “community” of cyber patriots he sought to protect critical infrastructure.
“Throughout his career, Mike informed presidents, shaped policies of foreign countries, helped establish standards for nations’ key resources, advised CEOs and leaders,” said SANS colleague Tim Conway, technical director of the institute’s ICS and SCADA programs. “But more important to Mike … has always been the individual lives that he has changed, that he’s invested in, and the things that those people have gone on to do in their own careers … throughout this industry.
“One of his most amazing skills has always been in identifying, connecting, motivating and enabling people to go on and do things that they wouldn’t have normally done. I’m one of those people who had the opportunity to work with Mike in a variety of different roles [and] organizations over the years. And [at] each one, he led me to challenges and to move in ways I would not have been comfortable with if he was not there with me.”
Jason Christopher met Assante while working at FERC and stayed in touch when he moved to the Department of Energy, eventually working with him at SANS. He remembers Assante approaching him when he was representing FERC during a NERC Critical Infrastructure Protection Committee meeting, where Assante was giving a presentation about the industry’s aging workforce.
“So much of my work about training … and trying to inspire others — I can pinpoint it to him coming up to me in the back of a room and just inspiring me,” said Christopher, now chief technology officer for Axio.
“The first couple times you [met him, you] realized he just kind of knew everything,” Christopher continued. “Everyone wanted his opinion … on how to do any project at DOE. If you told me that the HVAC vendor for DOE was asking Mike Assante’s opinion, I’d say, ‘Yeah that makes sense.’ Everyone wanted to get his perspective because he had seen so much and done so much already and helped the industry be what it is.”
Bryan Owen, cybersecurity manager for OSIsoft, who worked with Assante at INL, recalled a “red-blue” training at which Assante was one of the motivational speakers. “He would come in and just wow everyone,” Owen said. “And after that, I had guys coming back and telling me all the great things they wanted to do — they were turned on to do secure design and secure by default … Mike just had that gift.”
Owen also recalled Assante leading a group of reporters through the lab during a media tour following news of Stuxnet.
“One of the journalists asked, ‘Tell me about this Aurora test.’ Mike’s eyes lit up, and he started describing this [herky jerky] diesel generator that had served its purpose so well, and in its final act, it was sacrificed to prove that cyber really could take one of these things down,” he said. “You could just see everyone listening to him. And they all felt sorry for the generator.”
He also recounted a photo of Assante that was posted at a SANS cyber summit. “The message around that was, ‘We can’t sit back and be reactive when it comes to protecting infrastructure. We have to go out and hunt for these bad guys in our systems.’ That’s stuck with me ever since.”
INL named a classified conference room for Assante, said Zach Tudor, the lab’s associate director for national and homeland security science and technology. “Mike is a huge figure among all of us at Idaho National Laboratory,” he said. “If he would suggest, ‘Do you think you should do this?’ It was kind of like, ‘You better do this.’”
Fifth of July
Assante survived his first battle with cancer more than 15 years ago but learned — at GridSecCon 2017 — that his leukemia had returned, Conway said.
“He waited [to pass] until after the Fourth of July. I talked to him the day before and he said, ‘I don’t really want to go on the Fourth of July when everyone is supposed to recognize the nation and our freedom. I really hope I can make it another day. He really had control of this the whole way through.”
“And he didn’t want to die on July 6, which is his wife’s birthday,” wrote Dragos founder Robert M. Lee, who continued the story in a blog post titled, “Goodbye Mike Assante, Thank you For Literally Everything.”
“So essentially Mike chose the fifth,” Lee wrote. “That’s the kind of stuff we make up about people to pretend they’re a badass. But that was just another true story and small feat by Mike. Mike didn’t lose his battle to cancer; he kicked its ass a decade ago. It came back, and he told it, ‘No, you’re going to wait your turn.’”
Christopher said it was community that Assante was thinking about at the end. “My last conversation with Mike, he mentioned this community, the people in this room. And he said, ‘This is what’s important. It’s the community,’” he recounted. Assante said “to take care of each other because we’re all making a difference, and we’re doing what we do best, and we do it best together. He said to make sure that we talk about that. That we talk about us as a community. The specialness we have as a group.”
Assante left behind his wife, Christina, and three children, Alex, Anabel and Asher.
Tom Vanderhorst, Christina’s brother, ended the program with reminiscences of campfires at which his brother-in-law talked about his “community.”
“Along with being passionate about those he loved, he was also passionate about this community,” he said. “He was living his dream.”
The federal judge overseeing Pacific Gas and Electric’s bankruptcy named a mediator Monday to help the embattled utility and its bondholders negotiate a reorganization plan.
Lawyers for PG&E Corp. and its utility subsidiary Pacific Gas and Electric Co. have been pleading for a mediator for weeks to help them resolve differences with bondholders trying to take over the company. (See Attorneys Clash over PG&E Reorg, Blackouts Resume.)
Judge Dennis Montali, with the U.S. Bankruptcy Court in San Francisco, finally acquiesced, saying he hoped mediation would work now as it had in the utility’s 2003 bankruptcy, when a mediator helped PG&E and the California Public Utilities Commission hammer out a compromise.
“Now, more than sixteen years later in the utility’s second case (this time with parent company), the need for mediation is far more obvious and the stakes unbelievably higher,” Montali wrote in an order. “After presiding over every hearing in these Chapter 11 cases over the past nine months, the court is convinced that mediation should be attempted once again.”
Montali named retired bankruptcy Judge Randall J. Newsome as the mediator. Newsome, who works now for JAMS, the nation’s largest private mediation and arbitration firm, served on federal bankruptcy courts in Ohio and Northern California before retiring in 2010. He joined JAMS’ San Francisco office in 2011, according to a biography posted by the National Conference of Bankruptcy Judges.
Online biographies for Newsome do not list any utility-related experience, but Montali gave him authority to “recommend the appointment of one or more additional mediators who possess needed requisite expertise and experience to join him in his efforts.”
PG&E and its bondholders have been fighting for control of the company for months. On Oct. 9 the judge ended PG&E’s period of exclusivity — the time it had to propound its own reorganization plan without competition — and allowed the bondholders to submit their plan for potential confirmation. (See Judge Admits Takeover Plan as PG&E Starts Blackouts.)
PG&E argued Montali’s action hadn’t helped advance the bankruptcy process and asked again for a mediator.
“As we predicted at the exclusivity hearing, termination of exclusivity has not worked to promote a consensus,” PG&E lawyer Stephen Karotkin told Montali during an Oct. 23 hearing. “[W]e say to your honor, now is the time to promptly appoint a mediator. That is the way to move these cases forward.”
Randall Newsome | University of Pennsylvania
The competing plans differ in their sources of financing and the amounts they would set aside for victims of wildfires sparked by PG&E’s equipment. The bondholders plan allocates roughly $5 billion more to fire victims in cash and PG&E stock. The bondholders also claim to have more than $29 billion cash in hand, versus promises by PG&E’s creditors to provide more than $34 billion for its reorganization efforts.
The bondholders, a group of high-risk hedge funds and institutional investors, want to wipe out the equity of PG&E’s current shareholders and give themselves control of the company.
PG&E sought bankruptcy protection in January after a series of devastating blazes threatened the company with insolvency. They included the wine country fires of October 2017 and the Camp Fire in November, the deadliest and most destructive wildfire in California history.
Seeking to avoid additional wildfires, PG&E has turned off power to millions of California residents three times in the past week during dry, windy weather conditions. The latest round of shutoffs to roughly 600,000 customers began Tuesday.
PG&E’s stock sunk to record lows of less than $4/share Monday on news it’s equipment may have started the Kincade fire, which had burned more than 75,000 acres and destroyed 124 structures in Sonoma County as of Tuesday morning, according to the California Department of Forestry and Fire Protection.
Montali’s appointment of a mediator and other factors caused PG&E’s stock price to jump more than 20% during trading Tuesday to nearly $5/share. It traded at about $70/share prior to the October 2017 fires.
DTE Energy’s earnings fell last quarter despite gains for its electric business, the company said Monday during a call highlighting its recent push to reach zero carbon emissions by 2050.
The company reported third-quarter profits of $319 million ($1.73/share) compared with the $334 million ($1.84/share) a year earlier. Operating income fell 9 cents short of Zacks’ estimates of $2/share. DTE attributed the decline to expenses related to restoration activities after severe storms.
DTE Pinnebog wind park in the Michigan thumb region. | DTE Energy
Despite the performance, DTE increased its 2019 operating earnings guidance range from $6.02-$6.38/share to $6.06-$6.40/share.
Speaking to analysts on an Oct. 28 earnings call, CEO Jerry Norcia said 2019 “is shaping up to be a strong year as evidenced by our guidance increase.”
Chief Financial Officer Peter Oleksiak said DTE’s standalone electric earnings were $307 million for the quarter, $3 million higher than 2018, “largely due to the impact of new rates implemented in May, offset by rate base growth costs and cooler weather in 2019.”
“As a reminder, the third quarter of 2018 was one of the hottest quarters on record in our region,” Oleksiak said.
The call also focused on DTE’s recent decarbonization goal.
The company last month announced it was setting a “bold new goal” of net zero carbon emissions in its electric generation fleet by 2050. The utility had previously committed to reducing greenhouse gas emissions from electric generation by 50% from 2005 levels by 2030, 75% by 2040 and 80% by 2050.
“DTE Electric’s medium- and long-term plans aligned with the scientific consensus around the importance of achieving carbon emission reductions. We are fully committed to dramatically reduce carbon emissions. This is the right thing to do for our customers, our business and the environment. We are doing as much as we can, as fast as we can, to provide our customers and the state of Michigan with clean energy that is affordable and reliable,” Norcia said.
DTE’s new carbon reduction goals. | DTE Energy
DTE says reaching zero emissions will depend on retirement of its coal fleet, “thousands” of additional wind and solar megawatts, natural gas-fired generation and investments in carbon capture, large-scale storage and modular nuclear facilities.
The announcement comes as the Michigan Public Service Commission deliberates on DTE’s latest 15-year integrated resource plan, filed in spring. Environmentalists and renewable advocates have derided the plan as relying blindly on coal and natural gas resources and not including enough renewable energy. Multiple intervenors have urged the PSC to reject the plan. (See DTEIRP Draws Fire from Renewable Proponents.)
Norcia said progress continues on the $1 billion, 1,150-MW gas-fired Blue Water Energy Center to replace about 2,000 MW of retiring coal plants in southwestern Michigan.
“We broke ground last year and received all the necessary permits. The plant is a little over 30% complete with the turbines already on site and an expected in-service date of the spring of 2022,” Norcia said.
Norcia also reported progress on MIGreenPower, the company’s voluntary renewable energy program, saying commercial customers including Ford, General Motors, the University of Michigan and the Detroit Zoo have committed to using a combined 400 MWs of renewable power to date. Additionally, nearly 10,000 residential customers have “committed to a portion of their monthly bills [going] to renewable power,” he said.
DTE also reported the Michigan PSC last quarter conditionally approved its purchase of three new wind farms with a collective 455 MW in capacity, increasing the company’s renewables portfolio by nearly 50%. The wind farms are slated to come online at the end of 2020.
AUSTIN, Texas — An attempt by ERCOT legal staff last week to alert stakeholders that qualified scheduling entities (QSEs) will soon be required to submit certificates for the resale of electricity resulted in a bit of a kerfuffle.
Stakeholders pushed back against the proposal during the Technical Advisory Committee meeting Wednesday, complaining about what they saw as an added compliance burden and asking to see the legal opinion behind the proposal.
ERCOT Senior Corporate Counsel Erika Kane held firm, beginning her responses to repeated questions with, “Again…”
Other legal staff began filtering into the meeting room, with General Counsel Chad Seely eventually joining the fray.
“I haven’t heard all the discussion. I just got text messages,” Seely said, taking a seat at the table.
In teeing up the subject, Kane said that electricity sold in Texas for end use is a taxable good subject to sales tax, unless a tax exemption applies. The purchaser — the QSE — claiming a “sale for resale” exemption must provide a resale certificate to the seller to establish an exemption from sales tax. Tax-exempt entities, such as municipalities and cooperatives, can choose to provide a tax-exemption certificate.
Kane said ERCOT was only asking QSEs to conform with practices followed by other RTOs and ISOs, who have determined that their role as central counterparty raises a need for the certificates’ submission.
“We came to conclusion that looking at risk versus burden, this is the right path forward,” she said.
The subject had been discussed at the board level and with outside legal counsel, but not with stakeholders. Seely said that “through a lot of discussion,” staff felt it necessary to put in place a process to gather the sales tax resale certifications.
“Help us understand the onerous burden placed on QSEs to fill out this documentation,” he told stakeholders.
Reliant Energy Retail Services’ Bill Barnes said that while the certification may be simple, “it feels like ERCOT has had an awakening or a new interpretation of the protocols that has caused a concern and proposed to be resolved by pushing the burden onto all the QSEs.”
“It adds to the host of all other documentation we have to file when we register a new QSE or change a name and address, which some of us do quite a bit,” Barnes said. “It’s another form and requirement we need to remember to do, when it appears to us there’s an easier way to do it. We’re not getting a good answer as to why there’s not a simple statement in the protocols that clarifies ERCOT can’t and does not sell electricity to end-use customers.”
Noting the layers of laws ERCOT operates under, Seely said, “You can’t place a requirement that would usurp the Texas tax code in the protocols.”
Seely said there was no outside legal opinion to share with stakeholders — “Everything I’m saying has been run through outside counsel,” he said — and he seemed nonplussed when one member asked whether the state’s comptroller could come to the committee and offer its opinion.
“You want the comptroller to come into this forum?” Seely asked.
“The comptroller hasn’t had a problem with how we’ve operated for 19 years,” Morgan Stanley Capital International’s Clayton Greer said. “That’s baffling to me,” he added, referring to ERCOT’s proposed change.
“I don’t know why it’s baffling,” Seely responded. “Just because the comptroller hasn’t said anything doesn’t mean we shouldn’t be addressing the issue.”
Staff had intended to put out a market notice after first giving the committee a heads-up. Now they plan to return to the committee in November with additional information and a new plan for moving forward.
Staff told the committee they plan to ask the Board of Directors for permission to revise day-ahead and real-time prices for 13 operating days. ERCOT protocols require the grid operator to resettle prices to right the wrongs of any data mistakes.
Kenan Ögelman, ERCOT’s vice president of commercial operations, assured market participants that the price corrections will be made, but he said staff first need to finish their analysis. That data will be shared with the Wholesale Market Subcommittee on Nov. 6 and the TAC during its Nov. 20 meeting.
Ögelman said a May update to the ERCOT’s market management system, intended to model withdrawn outages in the day-ahead market and for reliability unit commitment where facilities were being restored, instead modeled all withdrawn outages. Outages withdrawn before their planned outage start date were erroneously modeled in the market as out of service.
“The transmission and distribution providers did everything exactly as they were supposed to,” Ögelman said. “It’s how our systems took that in and what they did with it. It was not about anything coming in incorrectly externally.”
“ERCOT should correct prices when they screw up the data,” said Beth Garza, director of the grid operator’s Independent Market Monitor. “This is an ERCOT-screwing-up-the-data thing. ERCOT has an obligation to correct and inform.”
When ERCOT became aware of the error in late September, staff began investigating prices for the May 30 to Sept. 25 operating days, Ögelman said. A patch was placed into production Sept. 26.
Staff identified erroneously modeled outages for the Aug. 20-21 and Sept. 16-25 operating days. They determined that only the Sept. 16-23 prices were eligible for board review.
Ögelman said the August prices could not be corrected, as they were outside the timeline for board review. However, staff were able to re-price the Sept. 24-25 days before the prices became final.
On Oct. 24, ERCOT notified market participants that a recent update to the energy and market management system led to incorrect real-time prices Oct. 16-21 for certain settlement points and energy metered for resources. The grid operator said it has corrected the Oct. 21 operating day prices, which were still within the review timeline.
ERCOT said it would begin the resettlement process about a week after the Dec. 10 board meeting.
TAC Approves BESTF Leaders, Scope
One month after approving the creation of a task force to best integrate battery storage into ERCOT, the TAC endorsed the group’s leadership and charter. (See “TAC Approves Task Force to Study Battery Energy Storage,” ERCOT Technical Advisory Comm. Briefs: Sept. 25, 2019.)
Members unanimously backed the Battery Energy Storage Task Force’s selection of ERCOT’s Ken Ragsdale as its chair and Lower Colorado River Authority’s Andy Nguyen to represent stakeholders as the vice chair.
Ragsdale demurred to Sandip Sharma, ERCOT’s manager of operations planning, as being the group’s real leader despite the title. “He’s our guiding light,” Ragsdale said.
According to its charter, the BESTF will develop policy recommendations for the TAC’s consideration that relate to the integration of battery energy storage resources into the ERCOT system.
Two issues are currently “pressing” on the task force, Ragsdale said. The first is filing Nodal Protocol revision requests (NPRRs) related to a single model to be incorporated along with real-time co-optimization upgrades in the first quarter of 2020. The second is beginning discussions by midyear on how to integrate hybrid resources (battery and thermal) and DC-coupled resources, where the battery and solar are both behind the inverter.
The group defines a single model as a future approach where the battery is a single resource. It defines the combo model as the current approach representing a battery as a generating resource and a controllable load resource.
“We hope to come up with a proposal in early January and get some ideas on what the solution is before the second quarter of 2020,” Ragsdale said.
The BESTF held its first meeting Oct. 18 and has two more scheduled this year. It plans to follow the same review process as the Real-Time Co-optimization Task Force (RTCTF) by first developing principles or key topic/concept (KTC) recommendations that will be used to write the revision requests. The group plans to bring its first KTCs to the TAC’s Nov. 20 meeting.
“We’re still doing our homework,” Ragsdale said. He said the group is checking with other grid operators, developers and the Electric Power Research Institute to understand the design drivers.
Energy storage roadmap | ERCOT
RTC KPs
The committee endorsed the largest batch of real-time co-optimization key principles — 19 in all — yet offered up by the RTCTF.
The principles (KPs) fall under three categories:
KP 1.1 (5): Defines ERCOT’s parameters in representing the disaggregation of ancillary service (AS) demand curves so that potential future changes in values and distribution will not require system changes.
KP 1.3 (1)-KP 1.3 (11): Outline the key mechanisms and timelines for submitted AS offers and the AS considered and awarded under real-time co-optimization.
KP 5 (1)-KP 5 (6): Identifies day-ahead market changes necessary to align day-ahead AS procurement with real-time co-optimization’s implementation.
ERCOT’s Matt Mereness, who chairs the RTCTF, promised more than 20 items in KP 5 before the group is finished.
The task force has six meetings left, with the final one scheduled for Jan. 22. “We’re going right up to the wire,” Mereness said.
Members Endorse 9 Revisions
TAC members approved six NPRRs, a change to the Nodal Operating Guide (NOGRR) and two system-change request (SCRs):
NPRR849: Clarifies the range of voltages at a generation resource’s point of interconnection and circumstances for which its reactive capability must be designed to meet.
NPRR902: Defines ERCOT Critical Energy Infrastructure Information (ECEII), adds items that are considered ECEII, specifies the restrictions imposed upon parties that receive or create ECEII, and provides a framework for the submission of ECEII to ERCOT.
NPRR937: Removes distribution-level and non-settlement metered block load transfers from deployment during Level 2 energy emergency alerts (EEAs).
NPRR965: Excludes a quick-start resource’s five-minute intervals from the generation resource energy deployment performance calculation when the resource is engaging in the decommitment process or telemetering “shutdown” status.
NPRR968: Updates Protocol language to comply with NERC reliability standards BAL-002-3 (Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event) and EOP-011-1 (Emergency Operations) by changing the physical responsive capability trigger for a Level 3 EEA to match a new most severe single contingency of 1,430 MW, to be implemented on Jan. 1, 2020.
NPRR969: Clarifies ERCOT is the final authority in qualifying market participants.
NOGRR197: Updates the responsive reserve service (RRS) manual deployment to provide flexibility in the amount of RRS capacity that is released to the security-constrained economic dispatch engine during scarcity conditions.
SCR800: Incorporates DC tie-scheduled ramp into SCED by updating the resource limit calculator’s formula to determine the generation-to-be-dispatched value and adding a scheduled five-minute DC tie ramp rate (DCTRR). The DCTRR will be calculated from the scheduled systemwide DC tie ramp multiplied by five and a configurable factor to capture the scheduled five-minute ramp.
SCR805: Allows ERCOT to automatically provide certain reports to requesting transmission service providers (TSPs) before they are posted to the market information system public area. TSPs will receive the reports once a formal request has been approved by ERCOT.
LEXINGTON, Ky. — FERC Chairman Neil Chatterjee’s EnVision Forum, held last week at the University of Kentucky, was a unique energy conference in several ways, from the diverse lineup of speakers, to the wide variation in panel topics.
Perhaps most unique, however, was its location.
It wasn’t just the fact that it was held in a university football stadium. Or that lunchtime dessert featured bourbon-frosted bread pudding.
For his inaugural annual event Oct. 21, Chatterjee chose his home state, a place dependent on coal mining for its economy and coal-fired plants for most of its power, with 75% of its electricity generated by coal last year, according to the U.S. Energy Information Administration. It’s the fifth largest coal producer in the U.S., and about one-fifth of all operating U.S. coal mines are located there, according to EIA.
And judging by several of the panels at the conference, the state doesn’t care too much about the national conversations in the electricity industry: the increasing penetration of renewables, the threat of climate change and the need to modernize the grid.
“Well first off, I want to not apologize for the things we haven’t jumped on the bandwagon for,” Kentucky Public Service Commissioner Talina Mathews said in opening “Lessons from Kentucky: A Case Study in the Energy Transition.”
“We remain vertically integrated. … We remain predominantly fossil fuel[-powered]. We don’t have a [renewable portfolio standard]. … But what we do have is reliable, baseload generation that serves our homes and also serves a large manufacturing base in Kentucky,” Mathews said. “We make things here, and I think that may be different from some of the other states that maybe have the ability to rely on more intermittent sources of energy. I don’t think an aluminum smelter is going to deal very well with anything under a 90% load factor.”
Chris Perry, CEO of the Kentucky Association of Electric Cooperatives, referred to an earlier panel entitled “Empowering 21st Century Energy Consumers with Technology,” which featured Jeff Riles of Google and Brian Janous of Microsoft.
“They were talking about … a two-way communication, where customers are really engaged, getting a carbon signal, adjusting their usage. Let me tell you, in rural Kentucky, that’s not happening,” he said.
A member of the audience asked whether utilities in the state disclose electricity usage to ratepayers. “Sure,” Perry said. His co-ops also provide voluntary demand response programs. “Guess how many people sign up? Not many. Not many. We find out they get excited for a short period of time, and then it’s, ‘I want to dry my clothes when I want to dry my clothes.’”
Another audience member asked the panel, which also featured Kentucky Power President and COO Brett Mattison and LG&E and KU Energy CEO Paul Thompson, if their utilities were seeing increased customer demand for renewables as in the rest of the U.S.
“We don’t have the best resources,” Mathews said. “I jokingly say Kentucky is the allergy capital of the world because the wind hits the plains and then all of a sudden it just stops, and we breathe pollen from April to November. …
“You would never build wind here if you can build it in Oklahoma,” she said, making a similar comparison with solar and Arizona. “So, we’ve heard, but we really haven’t had many of those [renewable projects] come to the commission.”
“You have many customers who sometimes will say, ‘Well we’d like to see some renewables; we’d like to see some zero-carbon energy,” Big Rivers Electric CEO Robert Berry said. “But they’re not really interested in paying for it.”
Berry said a co-op survey revealed 40% of its customers wanted to get their electricity from solar, but only 20% were willing to pay “some amount” more for it. Only about 5% were willing to pay 2 to 3% more, he said.
Kentucky had the seventh-lowest average electricity price in the U.S. last year and the lowest price east of the Mississippi River, according to EIA.
The argument that the switch to renewables would cost low-income ratepayers more was one that continually came up on an earlier panel entitled “All of the Above vs. Green New Deal,” the latter a reference to a Congressional resolution to transition the U.S. to 100% zero-carbon energy by 2030. Moderated by former FERC Commissioner Colette Honorable, the panel featured several state utility commissioners, most of whom criticized the Green New Deal as too costly for their customers.
“I represent the poorest region in the poorest state in the United States of America,” Mississippi Public Service Commissioner Brandon Presley said. “And the impact of an electric bill on a Mississippian is much more than it is in many other places in the United States of America. It affects our cost of living.”
“In the Eastern Kentucky footprint, where we serve, we have the same exact thing,” Mattison said on the Kentucky panel, referencing Presley. “Probably 30-plus-percent of the individuals find themselves at or below the poverty line. So when you look at transitioning to new sources, there’s always a cost associated with that. … We have constituents and customers who can’t afford to pay for that.”
Speaking on the earlier panel, Richard Kauffman, chairman of the New York State Energy Research and Development Authority, pushed back against these arguments.
“This issue of affordability I think is a red herring,” he said. “You [need to] create the right kind of innovation and market-related practices and change the financial incentives and business model for distribution utilities to be more system integrators as opposed to just being in the business of deploying capital — because that’s one of the reasons we have such low average capacity utilization.”
Wisconsin Public Service Commissioner Ellen Nowak responded. “I think it is a real concern. In my state, we have a lot of manufacturers, and the margins on their profit are very dependent on the cost of their energy. And as an economic regulator, we have to be smart about what we’re requiring them to pay for. That’s why this transition has to be done in a meaningful manner, not in a date that you set out and then figure out how you get there.”
“If we’re not careful, we’re going to burden all customers with a lot of stranded assets,” Kauffman said in reply. “Capital and energy inefficiency is a burden that we’re currently imposing on customers, and we can get more out of the customer bill. Think of that as a cost offload.”
Impact on Communities and Workers
Another panel focused on the impacts of the “new energy economy” on coal-dependent communities.
“Kentucky, like many states, has experienced firsthand the workforce and community impacts of our changing fuel mix,” Chairman Chatterjee said in an opening speech. “Behind every major energy project and company are dedicated energy sector workers. These women and men work hard to expand, improve and modernize our nation’s energy infrastructure and serve as the humming engine of our energy economy. …
“Right here in Kentucky, we’re in the heart of coal country. … The [coal] plant retirements that we’ve been seeing have real impacts on the workers, families and local economies here in Kentucky and throughout the United States.”
The panel wasn’t as dour as one might have expected, but it still illustrated the challenges blue-collar workers will increasingly face as coal plants continue to shut down and nuclear plants remain uneconomic to build.
Speakers included Brian Kerkhoven, energy policy adviser for North America’s Building Trades Unions, a federation of 14 unions that includes the International Brotherhood of Electrical Workers. Kerkhoven said his organization offers apprenticeship programs to train “out-of-work coal miners, who sure as hell aren’t going back to become nurses,” to become construction workers.
“We are now seeing a huge growth in our pre-apprenticeship program,” Kerkhoven said. “Not everybody has to go to college anymore, and we’re trying to lead that charge. … And that’s going gangbusters,” particularly in Texas.
He said renewables “don’t create the amount of jobs that coal, nuclear and even natural gas, to a certain extent, create. … Six to seven hundred people go to work every day at a nuclear power plant. A team of five to 10 go around and make sure the windmills are still spinning.”
Donnie Colston, director of IBEW’s Utility Department, concurred, saying the union’s members work on all resource types, but gas units, wind turbines and solar panels require very little maintenance compared to coal and nuclear plants.
“The good thing is … we’re being able to move” workers at shuttered coal plants “into other positions where members are retiring,” Colston said. “We’re not having massive layoffs.”
That still involves teaching workers a new trade. Utilities need to wait three to eight years, for example, for new linemen to complete their apprenticeship programs, he said.
Colston was incensed by the failure of states to approve interstate transmission lines, citing New Hampshire’s rejection of the 192-mile Northern Pass line that would have brought Canadian hydropower to Massachusetts, and Arkansas’ rejection of the 720-mile Plains & Eastern Clean Line, which would have transported wind energy in Oklahoma to the Tennessee Valley Authority.
“We worked for probably eight years with Eversource Energy” on Northern Pass, Colston said. “That was 2,000 jobs for IBEW. It came down to one vote on one committee that eliminated eight years’ worth of work. …
“Now, I don’t think we want to take away a state’s right to say you can’t build the lines, but if you want clean energy, as baseload comes off, you got to build lines,” he said.
Stakeholders are insisting PJM should manage critical infrastructure planning, telling the Board of Managers that a proposed Tariff attachment from incumbent transmission owners would violate the RTO’s governing documents.
LS Power and American Municipal Power are leading the chorus of dissent arising among stakeholders over Attachment M-4, which would establish a confidential process for mitigating the risks related to transmission facilities on NERC’s CIP-014-2 list — a subset of supplemental projects with regional implications that some members believe belong under the purview of PJM.
“PJM is a creature of both its Operating Agreement and Tariff, and PJM must pursue sound public policy consistent with the legal confines of both its Operating Agreement and Tariff construct,” LS Power wrote in a letter to the board Wednesday. “The proposed M-4 proposal construct has glaring inconsistencies with the existing regional planning process and the PJM Operating Agreement, which is controlled by the members of PJM, not the transmission owners.”
CIP-014-2 requires TOs to identify and protect transmission stations and substations whose loss or sabotage could result in widespread instability, uncontrolled separation or cascading outages. In August, incumbent TOs proposed outlining a process for vetting transmission projects in order to remove the assets from the list.
| Plocher Construction
Competitive transmission developers, consumer advocates, state commissions and other load interests argue the attachment is riddled with flaws that ultimately guarantee incumbent TOs control over a subset of complex supplemental projects with RTO-wide impacts, all under the guise of NERC-required confidentiality. (See PJM TO Tariff Filing Stirs Up Transparency Concerns.)
“Given the importance of these substations to regional and possibly interregional operations, there can be little question that the planning of those substations would be conducted through the PJM-administered regional transmission planning process,” AMP said.
PJM proclaimed its neutrality in the debate and only committed to the mutual agreement among all sectors that transmission planning should aim to eliminate the assets deemed critical within the RTO’s footprint, of which incumbent TOs say less than 20 exist. (See PJM Remains Neutral in CIP-014 Debate.)
But staff’s refusal to take sides hasn’t stopped stakeholders from taking their concerns straight to the board.
“We wish to emphasize that we can protect our critical energy infrastructure and maintain our national security, while also opening up the processes to build or upgrade such regional infrastructure to competition,” Securing America’s Future Energy (SAFE) said in a letter dated Oct. 3. “Contrary to the claim by the TOs, national security and market competitiveness are not mutually exclusive.”
SAFE further described a separate process for vetting CIP-014 projects as unnecessary and rejected the argument “that such transmission lines cannot or should not be allowed to be bid through a competitive process.”
In a Sept. 24 letter, the Organization of PJM States Inc. (OPSI) said that TOs should bring state commissions deeper into the CIP-014 planning process and specify how many critical facilities exist within each zone. The group also wants to know when these projects get factored into PJM’s Regional Transmission Expansion Plan and suggested TOs develop an assessment that balances cost and consequence reduction associated with each project.
The recommendations channel a problem statement and issue charged sponsored by the D.C. Office of the People’s Council that encourages stakeholders to develop a CIP-014 process inclusive of all sectors. The Planning Committee voted on Oct. 17 to postpone voting on the proposal pending a TO-led webinar to address questions. (See “Critical Infrastructure Vote Delayed,” PJM PC/TEAC Briefs: Oct. 17, 2019.)
Beyond PJM’s Control
The issue intersects with stakeholders’ overall concerns about supplemental project planning, which PJM insists it has little authority over. (See PJM TOs Sign off on Supplemental Project Deal.) Board Reliability Committee Chair Dean Oskvig said on Oct. 4 that the managers’ review of supplemental projects concluded that the RTO’s role “can be expanded in some areas but also remains appropriately constrained in others.”
“PJM does not have the authority or expertise to assume responsibility for asset management decisions or to determine when a facility is at the end of its useful life or otherwise needs to be replaced,” he said, referencing a failed AMP-sponsored problem statement and issue charge that wanted to open up these projects to regional planning. “Those decisions are the sole responsibility of the transmission owner.”
According to the Oct. 31 agenda for the Markets and Reliability Committee, AMP will present its failed problem statement and issue charge for a first read. (See “PJM Says No to End-of-Life Transparency Discussion,” PJM PC/TEAC Briefs: Sept. 11, 2019.)
Interim CEO Susan Riley echoed Oskvig’s sentiments in response to Consumer Advocates of the PJM States over what the organization called the unfettered growth of supplemental projects in comparison to necessary system upgrades planned by PJM.
“It is important for the PJM community to remain cognizant of where PJM’s authority and technical capabilities are positioned in relation to the planning and implementation of supplemental projects,” she said. “Identifying and verifying the need for supplemental projects, determining what goes into a transmission owner’s planning criteria and authorizing supplemental projects are responsibilities that extend beyond where PJM is situated as the regional transmission planner.”
In multiple responses addressing the CIP-014 process exclusively, Riley said the board understands the profound implications of these projects and said stakeholder comments provide constructive feedback for TOs in the ongoing development of their proposal.
“CIP-014 mitigation presents unique challenges related to the balance between significant risks imposed on customers and the transparency that has been at the foundation of the PJM planning process,” Riley told OPSI in a letter dated Oct. 8. “We discussed this matter at our last board meeting and commit to work with all stakeholders to develop a process that will allow the transmission owners to mitigate the risk associated with these critical facilities with PJM oversight.”
SCOTTSDALE, Ariz. — The often tense relationship between California and other Western states occupied much of this year’s Transmission Summit West, where the debate focused on whether states such as Idaho and Wyoming should draw closer to the Golden State or keep their distance.
The summit was held in conjunction with the Mountain West Renewables Summit, both organized by Infocast, at the Scottsdale Resort at McCormick Ranch.
Some speakers at the summits argued that a Western RTO made eminent sense, while others said their states didn’t want to feed California’s appetite for renewable energy without seeing enough benefits in return.
Arizona, for instance, is a politically conservative state with low electricity costs, said Michelle De Blasi, executive director of the Arizona Energy Consortium, a group that promotes the state’s energy industry. Arizona has the nation’s largest nuclear power plant, the 4,000-MW Palo Verde Generating Station, and one of the country’s youngest coal fleets, De Blasi noted. Both produce low-priced electricity that benefits Arizona ratepayers, she said.
Arizona’s electric utilities will take California’s solar power, particularly when there’s negative pricing, but they haven’t found interstate cooperation sufficiently useful to justify major investments, she said.
“It hasn’t made sense for them to go and build power lines and build generation feeding outside of the state,” De Blasi said. “We did not want to be a giant outlet for California.”
The state’s largest utility, Arizona Public Service, is a member of CAISO’s Western Energy Imbalance Market. Salt River Project and Tucson Electric Power plan to join in 2020 and 2022, respectively.
Some utilities of the interior West have determined the savings achieved through the EIM — a wholly voluntary, real-time interstate trading market — make it worth rubbing shoulders with CAISO, despite their states’ political differences with California. CAISO says the EIM saved its nine-member utilities more than $736 million in the past five years.
Interior states aren’t keen to get much closer to California than the loosely knit EIM, however.
Large areas of Wyoming and Idaho are served by PacifiCorp, an EIM member. But utility commissioners from those states expressed misgivings at the summit about serving California’s needs with renewable energy, paying for transmission upgrades or joining a CAISO-led RTO.
Who Pays for New Transmission?
During a panel titled “Enabling California to Access Out-of-State Resources,” David Smith described the TransWest Express, a proposed 730-mile transmission project that would link the wind-producing areas of Wyoming to Southern California via Utah and Nevada. Currently there’s little transmission linkage between California and Wyoming.
“TransWest is a project that would fill in that gap from Wyoming into the existing transmission capacity,” said Smith, the project’s director of engineering and operations.
The problem is, who pays for the project’s estimated $3 billion cost?
California would receive the energy to help fulfill its ambitious clean energy goals. Under last year’s landmark bill, SB 100, the state must rely entirely on carbon-free electricity sources by 2045.
Wyoming and other states would export that electricity, helping to offset the loss of coal production. A company controlled by billionaire Philip Anschutz, who also owns vast wind farms in Wyoming, would develop the project.
Smith suggested the costs of the new high-voltage lines should be shared among those who would benefit.
Public and private investors are part of the plan. The Western Area Power Administration is supporting the project through its Transmission Infrastructure Program, and the federal Bureau of Land Management is a backer. (See Wyoming Wind Power Revs up, but is it too much?)
Kristine Raper, a member of the Idaho Public Utilities Commission and an outspoken critic of California’s policy-driven energy goals, said she doesn’t see much upside to the proposal.
“Why would you socialize the cost of transmission in order for California to meet its renewable energy goals?” Raper said. “Idaho doesn’t have the same goals as California does in order to meet renewable energy,” nor does it need out-of-state electricity to meet its needs, she said.
Wyoming Public Service Commissioner Mary Throne expressed similar reservations in panels on Western regionalization and the allocation of transmission costs. She said Wyoming’s wind farms are no substitute for its once thriving coal industry, which has been shutting down.
“The number of renewable jobs will never replace the coal jobs we’re losing,” Throne said. “Coal to wind is not an even trade in Wyoming.”
Coal isn’t a “four-letter word” in Wyoming, like it is in California, she said.
“We kinda like coal in Wyoming,” Throne said. “It pays our bills.”
The idea of forming an organized Western electricity market, especially one with California leading it, generated even more controversy than the transmission line proposal.
In a presentation called the “Rationale for Western Grid Integration,” Johnny Casana, a senior manager with Pattern Energy Group, a San Francisco-based renewable energy firm, laid out his case for regional cooperation.
Historically, much of the West’s transmission has been built to serve load in California, which has a huge population compared with the sparsely inhabited states of the Intermountain West, Casana said.
In a decade, wind and solar projects may be cheaper to build than keeping natural gas and coal-fired generators running, he said. Inexpensive energy from windy states such as Wyoming and sunny ones such as Arizona could fuel the cities of the West Coast, benefiting all involved, he contended.
“This is a world we’re going into that is unlike the world we come from,” Casana said. “There’s a lot of winners across the board when we think of ourselves as a unified region.”
Compared to the West, the eastern U.S. is far more connected with greater generating capacity, he noted. RTOs are the norm in the Eastern Interconnection; the West needs to catch up, Casana argued.
“We have a shared destiny with our neighbors,” he said.
Some speakers agreed, particularly environmentalists from California advocating for a greater dependence on out-of-state renewables. The proposed expansion of the Western EIM, a five-minute market, to an extended day-ahead market (EDAM) is seen by many as the next step in the evolution of the West’s energy landscape.
Samuel Golding, president of Community Choice Partners, a Los Angeles group that advocates for community choice aggregators (CCAs), moderated a panel on the EDAM. Representatives of CAISO, the EIM and environmental groups spoke on the panel, supporting the move. Like the EIM, they said, the EDAM would be voluntary, with utilities keeping control of their assets and allowed to leave at will.
“If you don’t like it … you can get out of it the next day,” said Craig Lewis, executive director of the Clean Coalition, a nonprofit that advocates for a quicker transition to renewable energy. He criticized some from the interior West for disregarding the potential windfall if they join with California and help serve its energy goals.
“There’s this massive economic development to your states, and it doesn’t seem to be part of the consideration,” Lewis said.
During the panel on transmission cost allocation, Raper said the EDAM could increase the likelihood of a Western RTO. But she said there’s a slim chance other states will join an organized market whose leaders are chosen by California’s elected officials.
Members of CAISO’s governing body are appointed by California’s governor and confirmed by its State Senate — meaning the ISO’s agenda is dictated by the state’s progressive policy goals, she said. CAISO takes control, but not ownership, of the transmission lines of its member utilities. A Western RTO could only happen if California agrees to a board composed of representatives from other states, she said.
“It would be irresponsible for me as a regulator to cede all the assets of my utilities to California,” Raper said.
Given the costs and increasing impacts on resource choices that PJM market rules impose on states, states would benefit from a larger voice at PJM. Compared with its counterparts in other regions, the Organization of PJM States Inc. (OPSI) has less formal engagement and influence on PJM rules and decisions. Strengthening the role of OPSI’s 14 members (13 states and D.C.) would help ensure that states have meaningful opportunities to influence PJM’s rules and policies and could benefit everyone: states, retail and wholesale customers, and PJM.
One example of a PJM rule that impacts state renewable policies and costs to customers is PJM’s proposed change to its capacity market, the expansion of its minimum offer price rule currently under review at FERC. The proposal is estimated to cost customers in the PJM region an additional $5.7 billion per year.
PJM’s footprint | PJM
While the Federal Power Act generally provides PJM states a say over critical energy matters such as resource adequacy planning — how future energy needs will be met — states have seen their influence wane as PJM market rules and policies weight the scales that shape the mix and cost of capacity resources. As a result, PJM’s markets operate increasingly at odds with state energy goals, often at consumer expense.
Like many RTOs, PJM has an official auxiliary group through which states in theory can make their collective voices heard on policies and market rules: OPSI. Consisting largely of state public utility commissioners, OPSI monitors PJM, submits comments and interfaces with the RTO’s board and staff. Unlike state organizations in other RTOs, however, OPSI plays little more than an advisory role. PJM’s current structure leaves states without power to vote on proposed market rules or to file alternatives with FERC.
States’ abilities to directly influence RTO actions vary by region across the U.S. PJM states sit at one end of the spectrum, without voting ability and unable to file challenges with federal regulators. On the other end, states in SPP wield the most authority of any RTO state organization over generation and capacity matters. Taking a look at how RTOs in other parts of the country allow for state engagement is instructive as states in PJM strive for more voice and a better balance between their individual goals and the important role of the regional grid and markets. We overview several RTO/state models in a recent white paper.
Making PJM’s State Committee Work for States
Inspired by the examples of other RTO state committees, here are a few ways to increase the role and influence of PJM states:
Create stronger communication and collaboration between PJM and states: RTOs in other regions give deference to the views of state committees regardless of their rules. They prioritize a constructive working relationship.
Provide regular opportunities to provide formal input: OPSI should be able to weigh in on the design of PJM’s capacity market and transmission planning, both of which influence billions of dollars of supply investments and customer impacts.
Back OPSI’s feedback with bylaws: PJM’s governing documents could have specific opportunities for states’ input and require the RTO to say how it took OPSI’s input into account.
Give states more power to determine their own capacity needs: By adopting a provision like that available in MISO, individual states would be able to set their own targets for capacity reserves — rather than relying on a single target set by PJM — to better reflect state needs and energy goals.
Give states the option to supply their own capacity needs: A so-called “fixed resource requirement option” would give states and utilities more flexibility to meet demand on a megawatt-by-megawatt basis.
Give OPSI the power to make FERC filings: OPSI could be given the power to make its own filings to FERC under FPA Section 205, giving the states more power over resource adequacy planning.
Give states a role in selecting PJM’s board members: In MISO, for example, the state committee is often represented on the search committee for the RTO’s board members.
Require PJM to file states’ alternative proposals: PJM could have a provision where it must file an alternative approved by some percentage of OPSI members. In ISO-NE, the percentage is at least 60% of New England Power Pool participants.
These suggestions are not new, but the events of recent years renew their urgency: PJM is proposing significant changes to its market while searching for its next CEO, public utility commissioners have ongoing concerns about consumer costs, and many states are racing toward a renewable energy future.
Changing the balance of power between PJM and its states is critical to prepare the nation’s largest energy grid for the new energy era that lies ahead.
Ann McCabe returned to consulting after her term as a commissioner at the Illinois Commerce Commission (March 2012 to January 2017). Her recent clients include The Climate Registry, PJM Clean Energy Advocates and the Mid-America Regulatory Conference (MARC). While a commissioner, she was president of the OPSI board and of MARC and chaired NARUC’s subcommittee on Nuclear Issues-Waste Disposal.
David A. Svanda, a principal at Svanda & Coy Consulting, follows PJM, SPP, MISO and developments in other regions. He served as a Michigan PSC commissioner from 1995 to 2003, during which time he was President of MARC and NARUC. In those roles, he was an active participant in creating the concept and reality of regional state committees.
Betty Ann Kane served on the District of Columbia Public Service Commission for three terms (March 2007 to December 2018), including as Chairman (March 2009 to November 2018), and on the NARUC Board of Directors. She served as chairman of MACRUC and president of the National Regulatory Research Institute. Now a consultant, she has over 40 years of experience in public and private sector energy, finance and management.
