CARMEL, Ind. — MISO has terminated work on a new set of futures scenarios for the 2020 Transmission Expansion Plan (MTEP 20), opting to take the extra year to resolve its lagging renewable growth and retirement projections.
The RTO announced last week that it will recycle its MTEP 19 futures so it can finish MTEP 20 work early to allow time to completely retool the 20-year scenarios for the 2021 cycle. It introduced the idea to stakeholders in June. (See MISO Floats MTEP Time Trade-off.)
At a special workshop Thursday, MISO presented more evidence to back up its claim that a futures overhaul will be both necessary and time-consuming. The RTO said its members’ public announcements and stakeholder feedback indicate that fleet change in the footprint is occurring more rapidly than staff originally thought.
“We’ve seen on the ground [that] in the last three to five years, our members are taking actions that are outpacing even what we bookended. So, our planning is not managing that uncertainty,” MISO Director of System Planning Jesse Moser told stakeholders. “It’s time for a more full-fledged redo.”
Developing futures takes time that the annual MTEP cycles don’t allow, Moser said. “We feel rushed in this current process.”
Moser said utilities’ publicly available integrated resource plans alone indicate that the tempo of new wind and solar generation and coal plant retirements are already set to track above MISO’s highest predictions from MTEP 16, 17, 18 and 19.
Utility integrated resource plans versus MTEP futures predictions | MISO
In contrast with coal dominating in 2005, wind and natural gas generation have overtaken the interconnection queue, with a “huge” recent influx of solar in MISO South, Moser said.
“We’re seeing new resources that will have infrastructure in new locations and will have different operating characteristics. So, change is happening, and it’s happening faster than our scenarios have outlined,” he said.
MISO said the number of man-hours it spends developing futures jumped from about 1,000 hours annually in 2011-2014 to nearly 6,000 hours in 2018.
The Union of Concerned Scientists’ Sam Gomberg asked if MISO is considering ways for members to inform it of confidential retirement and generation plans to inform the futures.
Moser said the RTO is open to working more member communication into the process. He also said it will do more to incorporate state policies, carbon commitments and IRPs.
Clean Grid Alliance’s Natalie McIntire said MISO might consider looking beyond the next 20 years in planning, arguing that its recent transmission projects are not large enough to meet future needs. But consultant Roberto Paliza said the 20-year futures are too far in the future to be accurate, urging 10 or 15 years instead.
MISO is collecting sector opinions through the end of the month on how it should restructure the futures.
Stakeholders Split
Stakeholders offered differing opinions on the decision to reuse the MTEP 19 futures.
Entergy’s Yarrow Etheredge said a majority of MISO transmission owners support the cessation, provided “stakeholders are afforded an opportunity to recommend targeted economic planning studies in MTEP 20.” The Organization of MISO States also expressed support for the decision.
However, MISO’s Environmental sector disagreed, arguing that staff and stakeholders have already put work into the MTEP 20 futures. Invenergy’s Ann Coultas said stakeholders shouldn’t “be forced to choose between accurate MTEP 2020 assumptions and general improvements to the MTEP process.”
Northern Indiana Public Service Co., NextEra Energy and WPPI Energy also said MISO should develop MTEP 20 futures.
The possibility of a MISO–SPP transmission expansion must wait another year, as the RTOs have concluded their third coordinated system plan without recommending a single interregional project.
However, MISO and SPP staff promised they will seek to improve the coordination of their models and make another try in 2020.
The RTOs found no projects for which both would receive at least 5% of the total project benefit, MISO economic planner Gavin Christenson told stakeholders on an Interregional Planning Stakeholder Advisory Committee (IPSAC) conference call Monday.
The RTOs said they were able to “efficiently and effectively” evaluate more than 40 interregional project ideas through each of their regional processes. SPP used two future scenarios, while MISO employed the four future scenarios from its annual Transmission Expansion Plan. SPP requires project candidates demonstrate a 1:1 benefit-to-cost ratio for recommendation, while MISO requires a 1.25:1 ratio.
“While we don’t have a project to approve out of this CSP, it was not because of any process barriers. We still have model differences — this process was designed to take those into account,” SPP’s Adam Bell said.
MISO and SPP reported a smooth changeover to new joint operating agreement rules rolled out this year. The RTOs removed their joint modeling requirement and $5 million cost minimum in addition to calculating the benefits of adjusted production costs (APC) and the avoided cost of other upgrades. Bell said he didn’t notice any “barriers” to the study of potential interregional projects and reported that the RTOs engaged in regular communication throughout.
“We’re comfortable with each set of results. I don’t think these results are any indication that we’ll never have an interregional project,” Bell said. “That’s at least my perspective.”
The lack of interregional projects has long been a topic of debate. The RTOs’ CSP studies in 2014 and 2016 also failed to result in projects. At this month’s Mid-America Regulatory Conference, officials expressed interest in creating a small, interregional project type styled after MISO and PJM’s targeted market efficiency project. (See MISO-SPP Interregional Process Scrutinized at MARC.)
Bell thanked MISO for studying so many projects, especially on SPP’s Riverton-Neosho flowgate on the Kansas-Missouri border, where MISO studied nearly two dozen potential solutions. A new 345-kV line to ease the burden on the congested flowgate was one of the seven initially promising proposals.
“Obviously this area has been on our radar, and we wanted to do our due diligence on it,” MISO Interregional Planning Adviser Ben Stearney said of the RTOs’ most expensive flowgate. (See SPP Briefs: M2M Payments from MISO to SPP Eclipse $32M.)
M2M Payment Consideration
Stearney said MISO’s high market-to-market (M2M) payments on the Neosho-Riverton flowgate aren’t captured in APC savings in its model because generation is not redispatched to ease congestion on the line.
“It’s no secret that our APC methodologies have differences,” Stearney said.
Several stakeholders said M2M payments should factor into benefit analyses.
“I don’t understand why the MISO process hasn’t gotten in front of that Neosho-Riverton issue at all,” Missouri Public Service Commission economist Adam McKinnie said.
“This is leaving me concerned that this is not … properly capturing MISO’s cost” to use the flowgate above its firm service, WPPI Energy’s Steve Leovy said. “Unless I’m misunderstanding things, this looks like an appropriate thing to focus on.”
MISO staff promised a closer look at the impact of M2M payments in future interregional studies.
Models, Futures Coordination
Stearney also said the RTOs will pursue better model coordination but cautioned that their separate future scenarios will remain different, “driven by separate stakeholder processes.”
But later in the meeting, RTO staffs said they might consider creating interregional futures to use in the two separate regional reviews.
“Hopefully this thing will build on itself, and each year we’ll have more and more compatible models,” Bell said. “We do think that since we’re doing this annually, we’re going to get a lot better at incorporating everything we can feasibly. … That’s the hope in what this annual process will allow us to do.
“But there’s always going to be a disconnect,” he added.
He said this year, SPP and MISO made sure that the models, although different, “at least made sense.”
“The reasons we’re pointing this out is a sanity check. The [models] do show different benefits. That wasn’t unexpected,” Bell said.
Joint Model Nostalgia?
Advanced Power Alliance’s Steve Gaw asked if some of the modeling mismatch might have been resolved had the RTOs retained their joint model.
Bell said he thought there would be no difference in results with or without a joint model requirement.
“The joint model could have yielded a different result, but the analysis that we just went through would have been exactly the same in the regional review,” Bell said. “We were going to end up right back where we are.”
“You still have the rejection in the regional review. That’s where these projects get thrown out,” Gaw observed, saying he believed the interregional study process may be “broken.”
Bell said there simply wasn’t a project this year that could stand up to all the criteria.
Stearney added that MISO didn’t want to “compromise itself” by lowering the standards in its regional planning process. “We want to make sure projects stand up to criteria established on both sides of the fence,” he said.
MISO and SPP still must create a final, detailed CSP report to present to the IPSAC. The RTO staffs also said they’re taking early steps to begin the 2020 CSP. Representatives from both RTOs asked for stakeholders to submit additional written feedback on suggested improvements to the process.
“This was going to be a takeaway whether we had 10 projects [to recommend] or none — we’re going to improve the process,” Bell said.
FERC last week denied City Utilities of Springfield’s (Mo.) complaint against SPP’s regional cost allocation reviews (RCARs), saying the utility failed to show the RTO’s administration of the process was unjust and unreasonable (EL19-62).
Springfield filed the Federal Power Act Section 206 complaint in April, charging that SPP’s highway/byway cost allocation methodology has produced unintended consequences in its pricing zone that violated the cost-causation principle and the “roughly commensurate” standard.
City Utilities of Springfield HQ | City Utilities of Springfield
In asking for retroactive relief from its pricing zone’s costs, Springfield cited a 1982 D.C. Circuit Court of Appeals ruling that asserted that “properly designed rates should produce revenues from each class of customers [that] match, as closely as practicable, the costs to serve each class or individual customer.”
The commission rejected Springfield’s relief request, saying it “would be contrary to the filed rate doctrine and rule against retroactive ratemaking.”
FERC said SPP provides two avenues for members to dispute alleged “imbalanced cost allocations”: when the Regional State Committee makes an adjustment recommendation to the Board of Directors, or when a member asks the Markets and Operations Policy Committee to examine an alleged imbalance.
SPP’s transmission pricing zones | SPP
Springfield said SPP’s two RCARs have saddled its transmission zone in southwestern Missouri with the only benefit-cost ratio that does not meet the grid operator’s minimum threshold. The utility said the second RCAR allocated its zone $29 million more in costs than benefits, while customers in other pricing zones “will share in billions of dollars of net benefits.”
The protest drew numerous intervenors, including nearly two dozen SPP members and four state regulatory bodies. The Missouri Joint Municipal Electric Utility Commission supported Springfield’s argument, while Xcel Energy filed comments supporting SPP.
FERC last year approved a regionally funded project near Springfield that is expected to address some of the city utility’s issues. (See “FERC Approves SPP-AECI Morgan Transformer Seams Project,” SPP Briefs: Week of Oct. 8, 2018.)
FOLSOM, Calif. – Members of CAISO’s Market Surveillance Committee and stakeholders wrangled over systemwide market power and ways to limit it during an occasionally testy two-hour exchange Monday.
In March, ISO staff issued an analysis of market power in response to a similar report by the ISO’s Department of Market Monitoring, an independent body within the ISO. The staff analysis found its balancing area was uncompetitive during a limited number of hours in 2018 — primarily during times of peak demand when natural gas generators came online. Hot summer days, especially, allow some suppliers to game the system, staff said.
“If we were to design a systemwide market power mitigation process, how would it look?” Perry Servedio, lead market policy design developer at CAISO, summed up the process.
The DMM’s report had used somewhat different criteria but arrived at similar results and recommended the ISO take action to reduce the conditions in which market power might exist.
To address the findings, the ISO and the Market Surveillance Committee have convened a series of monthly stakeholder meetings with the goal of generating an opinion by October. They’re expected to present their findings on the potential costs and benefits of market-power mitigation to the ISO’s Board of Governors in November.
Among the topics being discussed are how to screen for market power and, if found, how and when to take steps to mitigate it. For instance, should the ISO screen only in the real-time market or also in the day-ahead market? And is it appropriate to mitigate voluntary supply?
Not everyone agrees with the ISO’s market-power assessment.
In a presentation at Monday’s meeting, Market Surveillance Committee member Scott Harvey said the ISO’s test for market power is “very conservative.” Failing to pass it doesn’t show the market is structurally non-competitive, he said.
“The test is designed to err toward over-identifying the potential for the exercise of material market power because it is not possible to apply a more sophisticated test in the time frame of the day-ahead market or real-time,” said Harvey, of FTI Consulting.
Others said the process now underway is moving too quickly toward issuing a November opinion. Instead of the usual straw proposal that’s part of a lengthy stakeholder process, ISO staff are planning to go to the board with a committee opinion, which they jokingly call a “straw dog proposal.”
Michele Kito, a regulatory analyst with the California Public Utilities Commission, told the committee the process seemed rushed.
“My concern is we’re going to go to the board with a (plan) that’s prematurely designed, and they’re going to say, ‘don’t do any further action,’ and I think that is a mistake,” Kito said. She noted many stakeholder initiatives take years to develop and said a measure dealing with market power deserves more consideration.
“I think to prematurely sort of cut the legs out of this, which I kind of anticipate … is a shame,” she said.
Public Citizen asked FERC Monday to rehear its ruling dismissing complaints over MISO’s 2015/16 capacity auction, saying the commission failed to justify its finding that there was no market manipulation.
The public interest group said FERC’s conclusion that Dynegy did not manipulate the market and that the ensuing $150/MW-day clearing price in Southern Illinois’ Zone 4 was reasonable was wrong on both counts (EL15-70).
The Zone 4 clearing price was a nine-fold price increase compared with just $16.75/MW-day a year earlier. MISO’s other nine local resource zones cleared below $3.50/MW-day that year. Public Citizen, the Illinois Attorney General and Southwestern Electric Cooperative had questioned Dynegy’s market behavior because the company controlled a significant portion of the capacity available in Zone 4.
2015/16 MISO PRA results | MISO
In mid-July, FERC wrapped up a three-year-old investigation into MISO’s 2015/16 Planning Resource Auction by finding no market manipulation on Dynegy’s part. The commission also found Zone 4’s $150/MW-day clearing price just and reasonable, declining to set up an evidentiary hearing to possibly recalibrate the auction results. (See FERC Clears MISO 2015/16 Auction Results.) FERC said a clearing price isn’t unjust simply because it’s higher than expected.
“The commission did not include the evidence from the nonpublic investigation in the record, did not allow the parties to address it and did not say in even the most general terms what, in its view, that evidence showed. Nor did the commission address the arguments advanced by the parties as to whether manipulation had occurred,” Public Citizen said. “The commission offered no account of what, in its view, Dynegy had in fact done or of why that conduct did not amount to manipulation.”
FERC ruled that although Dynegy had pivotal supplier status and that substantial price separation occurred between Zone 4 and the rest of MISO, the RTO had conducted the auction in accordance with its Tariff and market power mitigation rules.
Public Citizen said it didn’t appear that FERC examined whether MISO’s circa-2015 market power provisions were effective. The omission was “striking,” Public Citizen said, because just eight months after the auction, FERC ruled that MISO’s rules for the 2016/17 auction were not just and reasonable. FERC said MISO didn’t accurately gauge power exports and its $155.79/MW-day maximum bid should be set closer to $25. (See FERC Orders MISO to Change Auction Rules.)
Commissioners Cheryl LaFleur and Richard Glick expressed displeasure last month that they were not consulted before Chairman Neil Chatterjee closed the investigation. In a dissent, Glick called July’s order a “wholly unsatisfactory response to the allegations of market manipulation,” saying FERC didn’t provide “even the scantiest reasoning to support its finding that the nearly 1,000% year-over-year increase in the MISO Zone 4 capacity price had nothing to do with market manipulation.”
Tyson Slocum, director of Public Citizen’s Energy Program, acknowledged the group’s chances of prevailing in the rehearing request were slim.
“We’re in this for the long haul,” he said in an interview. “The request for rehearing is not necessarily to change the commission’s vote but to get this before a federal court.”
QUEBEC CITY, Quebec — NERC’s Board of Trustees on Thursday approved the Electric Reliability Organization’s 2020 budgets and a data request on supply chain issues before saying goodbye to retiring General Counsel Charles “Charlie” Berardesco. Officials also announced two executive appointments and the successor to Chair Roy Thilly during their two-day quarterly meetings in Quebec.
The board approved the 2020 ERO Enterprise business plan and budgets, which will be submitted for FERC approval later this month.
NERC and the REs are increasing spending by 3.9% to $207 million, with total assessments projected to increase by 2.9%.
NERC’s $83.4 million budget is a 4.5% increase over 2019 and will be mostly funded by $72 million in assessments, also up 4.5%. Canada (+7.3% to $0.013/MWh) and Mexico (+6.0% to $0.016/MWh) face bigger assessment increases than the U.S. (+4.3% to $0.016/MWh).
NERC’s budget includes $500,000 for modifications to its Atlanta headquarters to provide more meeting space. “We expect to save $150,000 a year” in meeting costs after the renovations, Controller Andy Sharp said.
NERC is projecting an additional 5.6% increase in assessments for 2021 and 5.9% for 2022, but those amounts could be reduced by releases from its assessment stabilization reserve.
The increases are being driven by the five-year expansion plan for the Electricity Information Sharing and Analysis Center (E-ISAC), which added nine full-time equivalent employees this year and plans to add seven in 2020 and 14 through 2022.
Excluding the 13.3% increase for the E-ISAC, ERO spending will increase by 2.2%.
Thilly acknowledged the ISAC budget increase “is significant and will continue to be,” thanking stakeholders for their “strong support” for the spending boost.
The Canadian Electricity Association and Ontario’s Independent Electricity System Operator had questioned the increase in the E-ISAC, with the CEA expressing skepticism over the ISAC’s “value proposition” to Canada. (See ERO Budget Nears OK Despite Canada’s Concerns.)
At the board meeting, CEA CEO Francis Bradley commended NERC for “working to be more aligned with the fiscal and regulatory realities faced by electric utilities” but expressed concern that spending is projected to exceed inflation for the next several years.
“The magnitude of the ISAC budget increases are substantial, and, as such, it is essential there is corresponding value for all the stakeholders.” Bradley said.
In its comments on the budget, the CEA said the E-ISAC should take advantage of capabilities already available from other agencies, including the Canadian Cyber Centre, to avoid unnecessary duplication and spending.
“We see ourselves as never having enough expertise to do it on our own,” Chief Security Officer and E-ISAC Director Bill Lawrence told the Technology and Security Committee meeting on Wednesday. “Efficiency in an area like this is very hard … because if something happens, you never spent enough and never did enough.”
NERC CEO Jim Robb noted the memorandum of understanding the E-ISAC signed with IESO this summer. “We’re very optimistic about benefits to come from that. We’re going to focus on that with great vigor in the coming year.”
Robb said although the E-ISAC has had success in hiring good talent and increasing its capabilities, it remains limited by the data flowing into it from industry.
“How do we get more information flowing voluntarily into the E-ISAC? … That’s going to be one of our big pushes this year in outreach,” he said.
Supply Chain Data Request
The board approved a datarequest on the “the nature and number” of low impact bulk electric system (BES) cyber systems. The data request was a recommendation of the staff supply chain report approved by the board in May. (See “Supply Chain Report Recommends Expanding Standards” in NERC StandardsNews Briefs: May 8-9, 2019.)
NERC said the information will help it understand the risks associated with low impact systems with external routable connectivity and determine whether to modify the supply chain standards to include them.
“We’re not looking for an exact count of low impact BES assets. Instead, it’s a count of locations,” Director of Engineering and Standards Howard Gugel told the Member Representatives Committee (MRC) Wednesday.
The request is expected to be issued this week, with responses due in early October. NERC will schedule a webinar to address questions from recipients of the request. A summary of the responses will be presented to the board at its November meeting.
Gugel said NERC received 35 sets of comments on the request. Some commenters thought the request should be expanded to include vendors.
Gugel said although NERC does not consider the results confidential, it will only share results in the aggregate; no individual entities will be identified.
New Format for Q4 Meeting
Thilly said the board will experiment with an abbreviated open meeting immediately after the MRC meeting on Nov. 5 in Atlanta rather than the normal schedule of a half-day meeting the day after the MRC.
The open board meeting will be limited to action items, with committee meetings done in advance as conference calls.
The board will also meet with the regional entity boards and hold a closed strategic session. The MRC meeting schedule will not change.
Thilly said the new schedule will be a trial that may be used for future fourth quarter meetings, which he said “seem to have least essential things” on the agenda.
“As long as I can remember, we’ve had an internal debate about whether we should continue with four meetings a year or three meetings,” Thilly explained during the MRC meeting Wednesday. “On the one hand, you can see [from] all the people here how important these meetings are … On the other hand, sometimes we feel like the day after this meeting, staff [are] spending a lot of time preparing for the next meeting, and that has an opportunity cost associated with it.”
“That’s what we intend to try in November. We’ll see how it works and what feedback we get,” he said.
Robb announced the appointment of Deputy General Counsel Sonia Mendonca as interim general counsel and corporate secretary, replacing Berardesco, who is retiring at the end of this month.
In addition, the Board of Trustees promoted Sharp to vice president. Sharp will also continue as the interim chief financial officer, a role he has served since the May departure of former CFO Scott Jones, who also served as chief administrative officer.
“Since Scott Jones left NERC after Memorial Day, Andy Sharp has effectively been our top financial executive,” Robb said. “I really appreciate him stepping in and stabilizing this organization.”
NERC last month hired an executive search firm to find permanent replacements for general counsel and chief administrative officer. (See NERC Leadership Search Announced.)
Stakeholders gave Berardesco a standing ovation for his seven years as general counsel and his nearly seven-month stint as acting CEO after the resignation of Gerry Cauley.
“He has been extremely dedicated to this organization,” Thilly said. “As everyone knows, he stepped into the breach in November [2017] as acting CEO. [He] really held everything together in a way that was quite seamless. No gaps. We will be forever grateful.”
Robb read a proclamation praising Berardesco, and SERC Reliability CEO Jason Blake thanked him for his mentorship.
“Charlie has meant a lot to me personally through his wise counsel,” Blake said. “One of the things he shared with me one time that really stuck with me was to do things with intention in all that you do. What is the purpose? That’s something that resonated with me. Something that I will take with me.”
Berardesco said it was an “overwhelming honor … to be able to spend this last part of my active career working on the other side” after almost 10 years at Constellation Energy.
He thanked the board members and his NERC colleagues and his “marvelous” deputy, Mendonca.
The board also announced Ken DeFontes will become chairman when Thilly’s term ends in February 2021. Thilly will remain on the board.
NERC also will be seeking a replacement for Janice Case, who will end her final term in February 2020. (The board increased to 12 members with the election in February of Colleen Sidford, representing Canada. It will drop back to 11 in February 2020 following the departure of Case and Frederick W. Gorbet.)
Nominating Committee Chair George Hawkins said the committee will meet in September to narrow the candidates to a short list to be interviewed in person.
At the board meeting Thursday, Robb asked ERO Insider to note he was wearing Boston Red Sox cufflinks and a New England Patriots tie in honor of departing FERC Commissioner Cheryl LaFleur. “We didn’t always agree on everything but always had a great opportunity for exchange,” he said.
Former NERC Chief Security Officer Mike Assante died July 4. | Sans Institute
Robb also noted the passing of Mike Assante, the head of SANS Institute’s industrial control system and SCADA security operations, who died July 5 of cancer. A former naval officer, he was NERC’s first chief security officer.
“We probably wouldn’t have the E-ISAC without Michael Assante,” Robb said.
He “left some big shoes to fill,” said Bill Lawrence, the E-ISAC director and current chief security officer.
Other Actions
The board also approved:
BAL-002-WECC-3 (Contingency Reserve): Replaces the Western Electricity Coordinating Council’s BAL-002-WECC-2a, Requirement R2, which became redundant with the implementation of BAL-003-1.1, Requirement R1 on April 1, 2016. WECC conducted a field test that concluded the retirement of the old requirement would not harm reliability.
Amendments to ReliabilityFirst’s bylaws to incorporate NERC’s Consolidated Hearing Process (Section 403.15 of NERC’s Rules of Procedure) and replace RF’s regional hearing process.
An update to the Compliance and Certification Committee’s (CCC) program for monitoring adherence to NERC’s Rules of Procedure for compliance monitoring and enforcement, which was last revised in 2015.
An update to the CCC’s procedure for qualifying for eligibility to submit implementation guidance to the ERO, last revised in 2016.
The federal judge overseeing Pacific Gas and Electric’s bankruptcy ruled Friday against bondholders and insurers that wanted to offer their own reorganization plans for the embattled utility, but he allowed fire victims to proceed with a lawsuit blaming it for one of the most destructive blazes in state history.
Judge Dennis Montali, of the U.S. Bankruptcy Court for the Northern District of California in San Francisco, said it wouldn’t be in the interest of fire victims to let competing Chapter 11 plans confuse the proceedings. He gave PG&E until Sept. 26 to offer its own plan without interference, in keeping with a so-called exclusivity period he had earlier granted the utility.
PG&E’s unsecured bondholders had offered it an injection of $30 billion, including $18.4 billion for fire victims, in exchange for guaranteed payment of more than $10 billion in notes, which otherwise could go unpaid in bankruptcy. PG&E’s lawyers argued the deal would give the bondholders — a group of banks, mutual funds and other investors — control of the company at a heavily discounted price and could lead to chaos in the Chapter 11 proceedings. (See Judge Weighs Competing PG&E Bankruptcy Plans.)
Montali agreed the plans would likely lead to unnecessary confusion and delay.
“Competing plans are tempting, and no doubt produce a feast for lawyers, accountants, investment bankers and others, not to mention the intellectual challenges to the court,” Montali wrote in his decision. “But the inescapable fact is that the fire victims and their insurers should not need to wait for conclusion of expensive, lengthy and uncertain disputes that only indirectly concern them.”
PG&E has said it will file its own plan by Sept. 9. A recent outline says the utility will pay its debts and compensate fire victims by raising money through stock offerings. In documents filed with the U.S. Securities and Exchange Commission earlier this month, two hedge funds — Abrams Capital Management and Knighthead Capital Management — pledged to backstop PG&E’s plan with $15 billion in equity financing to provide “a foundation upon which a more fully developed capital plan and plan of reorganization can be built.”
PG&E has “placed before all a proposal that, if coaxed and guided to maturity, should result in a proper outcome for all creditors without needing to deal with all of these other issues,” the judge wrote.
Judge Dennis Montali | Commercial Law League of America
Continuing his focus on fire victims, Montali decided that two cases could move forward in state court that allege PG&E caused the Tubbs Fire, which ravaged California wine country in October 2017 and burned down part of the city of Santa Rosa.
Investigators with the California Department of Forestry and Fire Protection determined a private landowner’s faulty wiring started the Tubbs Fire, but plaintiffs’ lawyers hope to convince a jury otherwise. The massive blaze killed 22 people and destroyed more than 5,600 structures in Sonoma, Napa and Lake counties. (See related story, Lawyers Argue over PG&E Wildfire Liability.)
Montali cited the plaintiffs’ estimates that the Tubbs Fire could account for two-thirds of PG&E’s liability for the 2017 and 2018 fires in Northern California that led to it declaring bankruptcy in January. Those fires include the Camp Fire, the deadliest in state history, which leveled much of the town of Paradise and killed 85 people.
Resolving liability for the Tubbs Fire will help the bankruptcy court determine PG&E’s estimated liability for those fires so that victims can be compensated appropriately, he said. Montali said that, despite PG&E’s objections, he didn’t think the lawsuits would interfere with the bankruptcy proceedings.
“The state court trial may proceed on a parallel track to the proceedings in this court,” the judge wrote in a separate ruling Friday.
ERCOT on Friday said it has approved NRG Energy’s plans to return its Gregory Power Partners cogeneration plant to mothballs in October. The plant, which returned to service in June for the first time since 2016, will be operated annually from June 1 through Sept. 30.
The Texas grid operator said it conducted a reliability analysis that determined the plant’s combined cycle units are not required to support system reliability during the portion of the year when they are mothballed.
The Sherwin Alumina plant, Gregory Power Partners’ cogeneration partner, shut down in 2016. | Sherwin Alumina
Gregory Power Partners, a three-unit, 365-MW facility located outside Corpus Christi, was shut down in late 2016 when its cogeneration partner, Sherwin Alumina, filed for bankruptcy and ceased operations. The plant was built in 2002.
NRG said in May it was returning the plant before the summer months to provide “additional reliability to our customers.” (See NRG to Bring Back Gas Plant for Summer 2019.)
DES MOINES, Iowa — Respect is the key to tempering landowner and community pushback on energy infrastructure projects, six industry experts told the Mid-America Regulatory Conference (MARC) last week.
The Aug. 13 panel agreed that in-person communication and avoiding a dismissive tone are needed to gain more traction in communities where contested projects are proposed.
“Land issues are just so critical. We talk about RTOs, FERC and seams, but this is really where it happens,” ITC Midwest Director of Public Affairs Tom Petersen said.
“Some of it has happened very easily, and some of it is quite painful,” moderator and North Dakota Public Service Commissioner Julie Fedorchak said of her state’s permitting of billions of dollars in projects.
Apex Clean Energy Vice President of Public Affairs Dahvi Wilson said it’s no longer simply a matter of getting landowners to sign off on projects. Now, Wilson said, utilities need to secure public support.
“We’re increasingly before state [and] local governments, and we’re facing opponents that are very sincerely concerned about what’s coming to their communities but also misguided,” Wilson said.
Utilities are increasingly facing the deliberate spread of misinformation online about proposed projects, she said. “We’re in a lot of debate right now over what’s true.”
Wilson said regulators must now ascertain whether data are scientifically rigorous or simply pulled from a questionable webpage.
North Dakota Indian Affairs Commissioner Scott Davis, a member of the Standing Rock Sioux tribe, led negotiations with the Dakota Access Pipeline over a two-year period. He described how he was constantly afraid of a protester’s death and listening to helicopters conducting crowd control near his home.
“Don’t underestimate the power of my people. You can tell them not to do it, and they’re going to do it,” Davis said. “Quite honestly, government hasn’t treated us very well in the decades of our existence.”
Davis said “old-fashioned” face-to-face discussions with tribal or community leaders is the best approach to introducing projects with communities, native or not. Davis also warned that treaties protect tribal land.
“[For] a lot of you that have tribes in your states, treaties are the law of the land. They’re in the Constitution. … Understanding tribes, where they’re coming from, is so important,” Davis said. “I think in this world of progress, progress, progress, what drives us — what pushes the gas pedal of progress — is trust. If you’re just rubber-stamping [energy infrastructure projects], you will have an issue.”
Wilson said the wind industry, which previously tended to submit projects quietly, hoping for little public notice, is now more transparent. She also agreed that it’s imperative for utilities to spend face-to-face time in a community.
“If the people that are fighting our projects are much more liked in the community, the community is going to believe them over us,” Wilson advised.
However, she said, it’s still a “hard sell” to convince many utilities to spend money to embed company representatives in a community to foster trust.
Considering Alternatives
Environmental Law & Policy Center Senior Attorney Brad Klein said it’s generally good practice for a utility to perform a full environmental impact analysis early in the process and thoroughly investigate alternatives to a large energy infrastructure project.
“I don’t think alternatives are appropriate in all cases, but they should be fully considered up front,” Klein said. Decisions should be made based on “full and fair information,” he said, which should contemplate new technologies, battery storage and collections of distributed resources.
Kevala Analytics CEO Aram Shumavon urged those thinking about project alternatives “to think about the amount of change we have been through in the prior 10 years versus the century before that.”
Klein also acknowledged that there will be environmental trade-offs with any large infrastructure project. But utilities and regulators shouldn’t insult groups of concerned citizens, he said.
“Don’t dismiss local communities as NIMBYs [‘not in my backyard’]. That’s insulting,” Klein said. “When we lose the public’s trust, you lose the larger fight.”
Petersen said he was in “violent agreement” that utilities shouldn’t reduce protesters to NIMBYs.
“Before you even propose a project, spend two months in the community. … You’ll decide whether that project is appropriate for that area. … And you’ll have a whole lot more respect,” Petersen said.
Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability Committee on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Valley Forge, Pa., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Consent Agenda (9:10-9:15)
The MRC will be asked to endorse proposed revisions to:
B. PJM Manual 10: Pre-Scheduling Operations, regarding generator outage reporting. The changes include clarifications for outage ticket end dates for deactivations and outage ticket requirements for black start service.
D. Manual 13: Emergency Operations and Manual 14D: Generator Operational Requirements, as part of the clarifications to the non-retail behind-the-meter generation business rules. The changes will clarify the reporting, netting and operational requirements of NRBTMG and PJM’s responsibilities, processes and procedures. (See “BTM Generation Clarifications,” PJM OC Briefs: Aug. 6, 2019.)
E. Manual 18B: Energy Efficiency Measurement & Verification, resulting from a periodic review.
1. PJM Manual 14B Amendments (9:15-10:15)
After eight months of discussion, PJM will present “compromise” revisions to Manual 14B that expand upon how the RTO prioritizes projects in the Regional Transmission Expansion Plan. The RTO said that it “commits to implement” the manual changes if they are approved by the MRC.
In its presentation, PJM said the language doesn’t address all of the concerns raised by LS Power and other stakeholders at the special Planning Committee meetings held since January about how and when supplemental projects move in and out of the RTEP.
The revisions are intended “to ensure that the manual faithfully documents its existing planning processes, integrates new processes or procedures consistent with recent regulatory orders/compliance directives, and provides a platform for the future that incorporates stakeholder desires, duties and future direction,” according to PJM’s presentation, posted online last week.
LS Power will also review its original main motion that’s been the center of PC discussions. The company intends to accept language presented at the special Planning Committee session Wednesday as a friendly amendment.
American Municipal Power will also propose friendly amendments to the Wednesday proposal.
Greg Poulos, executive director of the Consumer Advocates of PJM States (CAPS), will review OA revisions proposed by the D.C. OPC concerning updates to the RTEP.
The language would prevent PJM from unilaterally shelving endorsed rule changes without any recourse for disgruntled members, as it did in January with stakeholder-endorsed transparency language that PJM found inconsistent with FERC rulings. (See Tensions Boil over on PJM’s Supplemental Projects.)
The committee may be asked to endorse the proposed changes.
