The New England Power Pool Reliability Committee (RC) on Wednesday reversed its September rejection of ISO-NE’s proposed installed capacity requirement (ICR) calculations for Forward Capacity Auction 14 (2023/24) and three annual reconfiguration auctions (ARAs) to be conducted in 2020.
A restored End User sector quorum and a break in the ranks of universal opposition from the Generation sector proved the tipping point. Needing a 60% majority to recommend the ICR values to the Participants Committee, the RC voted by roll call and passed the motion with 63.49% in favor. The RC approved net ICRs of 32,205 MW for 2020/21 ARA 3, 32,230 MW of 2021/22 ARA 2 and 32,465 MW for 2022/23 ARA 1.
The Generation sector voted 4.2% in favor and 12.59% opposed, with one abstention. The Transmission and Publicly Owned Entity sectors remained unanimous in favor, Alternative Resources remained approximately split, and the End User sector was recorded unanimously in favor with one abstention.
Capacity commitment period 2020/21 ARA 3 systemwide capacity demand curve | ISO-NE
The committee also approved a 940-MW value for the Hydro-Québec interconnection capability credit (HQICC) for FCA 14’s ARA 3, with the value rising to 958 MW for ARA 2 and 969 MW for ARA 1.
Peter Wong, ISO-NE manager of resource studies and assessments, and Senior Engineer Manasa Kotha presented the ICR values and tie benefits.
Pending PC approval on Nov. 1, the RTO plans to file the ICR-related values with FERC by Nov. 5.
$46 Million PTF Cost Allocation
The RC voted to recommend that ISO-NE approve pool-supported pool transmission facility (PTF) costs of $46.39 million for the Baird 115-kV line rebuild project in Connecticut, per the revised cost allocation submitted by Avangrid/United Illuminating.
The committee found the costs consistent with the criteria set forth in Section 12C of ISO-NE’s Tariff for receiving regional support and inclusion in pool-supported PTF rates, and that none of the costs associated with the upgrade are considered localized costs.
The project involves rebuilds of the 88006A and 89006B lines between Baird substation, Barnum substation and the Devon Tie switching yard tying into the Housatonic River Crossing project, for a total distance of approximately 2.4 miles, and includes installing new galvanized steel transmission poles supporting new aluminum conductor steel-supported cable and optical ground wire.
Based on a show of hands, the motion passed with none opposed and no abstentions.
Other Action
The RC on Wednesday also approved a number of projects, including recommending that ISO-NE approve implementation of the Scitico substation circuit breaker and transformer addition project by Eversource Energy in Connecticut, as well as the 15-MW Davenport Solar Generation project by NextEra Energy Resources in Vermont.
The committee also recommended that ISO-NE approve implementation of Eversource’s Andrew Square-to-Dewar Street Station 115-kV cable installation project in Boston; New England Power’s 40-plus-MW Iron Mine Hill Road solar generation and transmission project in Rhode Island; and the latter’s King Solar 1 and 2 generation project.
It also approved revisions to Operating Procedure 16J to modify the timing for initiating the annual certification of transmission equipment dynamics data; and revisions to Operating Procedure 2A, to modify the table of itemized equipment maintenance of communications, computers, metering and building services.
Attorneys in the Pacific Gas and Electric bankruptcy case sparred Wednesday over the merits of their competing reorganization proposals, taking potshots at each other’s plans but not scoring any obvious points with the judge overseeing the proceeding.
The hearing was the first since U.S. Bankruptcy Court Judge Dennis Montali ended the utility’s exclusive right to submit a restructuring plan. The decision allowed the company’s unsecured bondholders to submit their own proposal, which has won the support of a group representing wildfire victims, the court-appointed Tort Claimants Committee (TCC). (See Judge Admits Takeover Plan as PG&E Starts Blackouts.)
The hearing also coincided with PG&E’s announcement that it would cut power to customers in 17 Northern California counties in the second series of public safety power shutoffs (PSPS) orchestrated this month to prevent wildfires. The blackouts commenced Wednesday morning and continued into Thursday.
The bondholders’ attorney, Michael Stamer, came out swinging early in the hearing. He disparaged the feasibility of PG&E’s reorganization plan and urged Montali to schedule a confirmation vote for the bondholder proposal as soon as possible — a move that would effectively prioritize the plan over the utility’s.
“We think the most efficient way to get to the end zone — which is confirmation [of a plan and] satisfaction of AB 1054 — is to allow our plan to go first,” Stamer said, referring to the new California law that allows PG&E to draw on a $21 billion fund to cover wildfire damages if it wraps up its reorganization by June 30, 2020. (See Calif. Wildfire Relief Bill Signed After Quick Passage.)
Stamer said the bondholder plan would also accelerate a separate state court proceeding convened by Judge James Donato to settle wildfire victims’ claims against PG&E over the October 2017 Tubbs Fire, which killed 22 people and leveled a section of Santa Rosa. (See PG&E Bankruptcy Split into Three Parts.) He contended the plan would “remove the burden” from Donato to estimate damages because bondholders have already negotiated a settlement with the TCC to cover claims of up to $13.5 billion for that fire. The PG&E plan caps the claim amount at $6.9 billion.
Montali was skeptical of Stamer’s argument.
“There’s a whole group of lawyers on the other side who think the burden is not gone — it’s still there. It’s called evaluation,” Montali said, questioning whether the bondholder’s plan might “overpay” tort claimants at the expense of other parties.
Montali added that the bondholder plan might be “DOA” if Donato “puts a larger number” on the claim.
“Our plan is DOA if he puts a very small number on them,” Stamer retorted. Nevertheless, the parties supporting either plan would have to “scramble” if the settlement lands between $6.9 billion and $13.5 billion, he said.
“They’ll scramble to come up, and we’ll scramble to come down,” he said.
Stamer said the “biggest difference” between the two plans is that PG&E’s financing is contingent on the $6.9 billion top-end estimate for potential Tubbs Fire claims.
“Unequivocally, they have to get Judge Donato to say that there is less than $6.9 billion of tort claims, or their financing disappears,” he said.
Montali pointed out that PG&E has said it will come up with additional financing if needed.
“We actually refer to that as the ‘stroke of the pen’ argument,” Stamer replied. “The debtors are of the view that if they get a different view from Judge Donato, with the stroke of a pen, what we will do is we will raise more money.
“So, here’s one of the fundamental problems — the world doesn’t work that way. No. 2 is the bulk of their money coming from equity holders. Setting aside the $30 billion of bridge loans, it has to come from equity holders.”
“You might say that doesn’t happen in the real world, and I might agree with you. That’s why you schedule a hearing — to prove the feasibility,” Montali said.
The judge firmly rebuffed the notion that he could shelve PG&E’s plan in favor of the bondholders.
“I have to do what the [bankruptcy] code says … and I don’t think it says I can dump a debtor’s plan because another plan is confirmable,” Montali said.
No Altruists
PG&E attorney Stephen Karotkin complained that Montali’s decision to terminate PG&E’s exclusivity “has not worked to promote a consensus” in settling on a reorganization plan.
“As we told you, the [Ad Hoc Committee of Unsecure Bondholders] and the TCC have become polarized entirely and now want to move forward with their own plan. That’s not the way it should work,” Karotkin said.
“At the exclusivity hearing, your honor, the TCC made very clear to you that they would only engage in mediation if you agreed to terminate exclusivity,” he said. “Having done that, we say to your honor, now is the time to promptly appoint a mediator. That is the way to move these cases forward, and let’s see if the TCC will live up to its word and its commitment to this court to mediate.”
Karotkin contested the bondholders’ contention that financing for the PG&E plan would fall apart if the Tubbs Fire claims exceed $6.9 billion, saying there is “ample capacity in both the debt and equity markets to fund the plan and meet the requirements of AB 1054. The debtor’s plan does not vaporize.”
He said Stamer was promoting the misconception that PG&E’s financing must come from the existing equity holders. “It doesn’t. There’s no requirement that it comes from the existing equity holders,” he said.
“The ad hoc bondholders are not a group of altruistic investors willing to put up money on favorable terms in an effort to save the state of California,” Karotkin said. “Any number of financial institutions have advised the debtors that there is adequate capital necessary … and on substantially better terms than the terms that are being provided by the ad hoc bondholders.”
Montali assured Karotkin that PG&E’s plan was still a contender.
“I may have disappointed you because I ended exclusivity, but I didn’t say your plan was out of the running,” Montali said.
“Neither one is perfect yet, and neither one is confirmable yet. But both are potentially confirmable,” he said.
Montali declined to rule on scheduling the confirmation of either restructuring plan. Hearings in the proceeding are slated to continue at least into early next year.
Shutoffs Resume
By Thursday morning, PG&E’s latest round of shutoffs covered nearly 183,000 customers — or about 540,000 people — in the Sierra Foothills and North Bay regions, where a “Diablo” wind event was bringing peak gusts of 65 miles per hour in conditions of extremely low humidity.
“Once the high winds subside, PG&E will inspect the de-energized lines to ensure they were not damaged during the wind event, and then restore power,” the utility said in a statement. “PG&E will safely restore power in stages as quickly as possible, with the goal of restoring the vast majority of customers within 48 hours after the weather has passed.”
PG&E tweeted that customers currently impacted would be restored in advance of any further PSPS initiated this weekend. The company said it forecasts indicated “elevated” risk of additional blackouts on Sunday and Monday.
PG&E’s incited a backlash from California regulators and Gov. Gavin Newsom over its decision to shut power to more than 2 million residents earlier this month. The company has defended its decision and last week signaled it will continue the PSPS policy for years until it hardens its system against wildfire danger. (See PG&E Says Blackouts Will Continue.)
CARMEL, Ind. — MISO is rearranging its Integrated Roadmap schedule to update the list of market improvements annually instead of the existing nearly two-year timeline.
The RTO said it will cut the Integrated Roadmap from 20 months to 13 months to put it in sync with the MISO’s annual budget process and the Independent Market Monitor’s yearly State of the Market Report. The Monitor’s recommendations are regularly folded into the ongoing list of market improvements.
MISO is suggesting a one-time shift of the Integrated Roadmap to cut seven months out of the process from recommendation to numbered roadmap item. After the change, stakeholder prioritization of recommendations will take place in March instead of July.
At an Informational Forum on Tuesday, market strategy team member Christov Churchward said the move to the new timeline will be implemented by the end of the year, nudging the new issue submission for the 2020 roadmap to Dec. 23 instead of the usual cutoff in the beginning of May. MISO and stakeholders’ issue prioritization is slated to begin Jan. 22 and wrap in the first half of April.
“This will continue to make the Integrated Roadmap even more integrated,” Churchward said.
MISO plans to hold a workshop Nov. 7 to discuss which improvements it will undertake with stakeholders from 2020 through 2025. (See Stakeholders Confused over MISO Roadmap.)
Prices, Peak Stay Low in Hot September
MISO’s average load in September nearly matched load at the same time last year, though peak loads stayed significantly below September 2018.
The RTO reported a 79.5-GW average load throughout the month, in line with the 79.4-GW average load in 2018. It hit an almost 107-GW peak on Sept. 11, well below the 115-GW peak on Sept. 4, 2018.
MISO said parts of its South and Central regions were 6 to 7 degrees Fahrenheit above the National Oceanic and Atmospheric Administration’s 30-year September historical average.
“We had a warm enough September this year — even warmer than last year,” Executive Director of Market Operations Shawn McFarlane said.
MISO systemwide prices September 2018 to September 2019 | MISO
The RTO called a hot weather alert in MISO South for Sept. 5-9, when average high temperatures stayed above 95 degrees. Despite this, MISO was able to keep “good supply availability,” McFarlane said.
In mid-September, RTO executives predicted MISO’s forecasted 112-GW fall peak wouldn’t come to pass with the worst of September heat behind the footprint. (See MISO Unruffled by Fall Supply-demand Outlook.)
Despite warm weather loads, prices stayed low, with MISO averaging a $24.61/MWh real-time LMP — a 27% decrease compared to September 2018 when real-time prices averaged $33.82/MWh. McFarlane said the low prices were a product of strong natural gas supply and low fuel prices.
Xcel Energy CEO Ben Fowke on Thursday dropped a reference to a classic John Belushi movie in explaining the company’s plans to invest more than $22 billion over the next five years in transmission and renewables.
“Like The Blues Brothers, [we] are on a mission to put the band back together again,” Fowke told financial analysts Thursday during the company’s third-quarter earnings call, referencing the now completed CapX2020 initiative. The project, developed with 10 other Midwest utilities, resulted in the construction of 800 miles of 345- and 230-kV transmission lines at a cost of $2 billion.
Fowke said Xcel is working with the original CapX utilities on a CapX2050 Transmission Vision study to maintain a reliable grid as the system adds more carbon-free energy.
| Xcel Energy
The company has updated its investment plan, which now reflects the $22 billion in capital expenditures. The forecast is driven by Xcel’s investment in renewables “as we continue the clean energy transition,” Fowke said.
“I don’t think this is a very quick process,” CFO Bob Frenzel said. “I think this is going to take at least five years through planning before we start getting into real capital plans and construction time frames.”
Fowke and Frenzel both noted that friendly right-of-first refusal legislation in Minnesota and Texas will help create opportunities in building transmission. (See Court Upholds Minn. ROFR, MISO Cost Allocation.)
Minneapolis-based Xcel reported earnings of $527 million ($1.01/share) for the quarter, up from $491 million the same period a year ago ($0.96/share). Xcel fell two pennies short of expectations; an Investing.com poll of analysts projected earnings of $1.03/share.
The company narrowed its 2019 earnings guidance range to $2.60 to $2.65/share, representing the upper half of its original range of $2.55 to $2.65/share.
Xcel’s share price opened at $64.95 on Thursday but was trading down after hours at $64.54.
A federal judge ruled Wednesday that only the Ohio Supreme Court can determine whether state law thwarted a citizen advocacy group’s ballot petition against nuclear plant subsidies.
Judge Edmund A. Sargus Jr., of the U.S. District Court for the Southern District of Ohio, denied Ohioans Against Corporate Bailouts’ motion for a preliminary injunction after the group claimed 38 days of its 90-day allowance to collect signatures were wasted in a “blackout period” during which it sought the attorney general’s approval of the petition’s language before circulation could begin.
The group has alleged a well-funded opposition harassed and bribed its petitioners, further complicating its effort to gather 265,774 signatures by Oct. 21. (See Ohio Nuke Petition Misses Signature Deadline.)
“This 90-day period they claim is burdened arises from the Ohio, not the federal, Constitution,” Sargus wrote. “Whether the Ohio Constitution guarantees a full 90-day period for petition circulation, and whether the statute’s requirements ‘burden the 90-day period,’ is a question beyond the jurisdiction of this court. Instead, these questions should be resolved by the Ohio Supreme Court.”
Perry Nuclear Power Plant, located about 40 miles northwest of Cleveland
Ohioans Against Corporate Bailouts has led a campaign against Ohio’s House Bill 6 — a $150 million nuclear subsidy program funded with ratepayer surcharges — having begun organizing petition efforts the same day Gov. Mike DeWine signed the legislation in July. The group fell nearly 45,000 signatures short of the count necessary for the referendum’s inclusion on the 2020 ballot, according to documents filed Wednesday.
“We look forward to making our case to the Ohio Supreme Court that the petitioning ‘blackout’ period is an unfair infringement on our constitutional right to referendum,” Gene Pierce, the group’s spokesperson, said in a statement. “Ohioans deserve the opportunity to vote on House Bill 6, and the despicable campaign by supporters of the bill to prevent that should not be rewarded.”
William Rogers, president of Advanced Micro Targeting, the Nevada-based company that managed the referendum effort, said in court documents that he had never encountered a “more hostile environment” in any other state throughout his 30-year career. He said Ohio’s draconian preregistration requirement, coupled with the opposition’s abuse of public records to target petition circulators for harassment and bribery, undercut the group’s efforts. (See Federal Court Waives Ohio Preregistration Law.)
Rogers said he knew in late September that the constant interference would prevent the group from meeting its deadline, so he began contracting with pay-per-signature firms to keep the campaign on track — to no avail. He claims the opposition poached 900 circulators between Sept. 3 and Oct. 21 by offering up $2,100/day to peddle a “fake petition.” AMT, by comparison, paid just $150/day.
Rogers told the court he estimated that it would take about 75 days to gather the necessary signatures and had initially expected circulators would collect around 4,100 per day.
Secretary of State Frank LaRose, the state’s chief election official and a defendant in the lawsuit, argued that the so-called blackout period is an “elections-mechanics rule that sets forth certain procedures for the referendum process” and doesn’t preclude advocates from promoting a petition in public discourse. He said that questions about whether the Ohio statute intends to give petitioners a full 90 days just for collecting signatures is worth exploring, but not in a federal court.
Sargus agreed, noting that the Ohio Supreme Court could give the group the remedy it seeks: a stay of HB 6 and additional time to circulate its petition.
“At the heart of plaintiffs’ claims is [the] proposition that the Ohio Constitution affords them 90 days to circulate a referendum petition, and that their First Amendment rights are violated by the statute because of the blackout period,” he said. “But Ohio courts have not held whether the 90-day period is guaranteed for circulating, or whether the required review by the attorney general violates the Ohio Constitution.”
Tom Becker, spokesperson for FirstEnergy Solutions, said Thursday the court’s decision “ensures that its citizens will have lower electric bills and cleaner air.” The company previously warned that it would resubmit deactivation notices for its Perry and Davis-Besse nuclear plants should the advocacy group succeed in its efforts. FES rescinded deactivation notices for both facilities in July after the state approved HB 6. (See Ohio Approves Nuke Subsidy.)
“We are pleased that our state will continue to benefit from diverse energy resources and that more than 4,000 jobs have been saved at our carbon-free, reliable nuclear power plants,” he said.
NEW ORLEANS — The outgoing president of the Organization of MISO States used his final address to the MISO community to once again press the RTO to develop a long-term transmission plan.
“We came together to encourage MISO to come together and study long-term transmission needs,” OMS President Daniel Hall said Thursday during a look-back at the organization’s 2019 accomplishments at its annual meeting. Hall attended the meeting via telephone, kept home by illness.
“There is nothing radical in these principles. … However, our goal was to jump-start the conversation on long-term needs in the footprint,” Hall said, referring to the set of transmission planning principles state regulators released in June. OMS has for months insisted that the RTO study creating a long-term transmission planning package similar to the 2011 multi-value project (MVP) portfolio. (See MISO Cracks Door on Long-term Tx Planning.)
In a review released earlier this month, MISO said the MVP package continues to show $16 billion to $57 billion in benefits, with a benefit-cost ratio ranging from 1.8:1 to 3.1:1.
“The current planning process is not sustainable. In fact, many stakeholders would say it’s broken,” Hall said. He urged MISO to put together a “thoughtful and comprehensive” long-term transmission plan study.
“Failure to do so will result in missed opportunities,” Hall said, referencing reliability benefits, reduced customer costs and accommodation of a growing renewables fleet.
MISO CEO John Bear said OMS’ long-range transmission planning principles are “a great call to action.”
OMS members also elected Minnesota Public Utilities Commissioner, and current vice president, Matt Schuerger as their 2020 president, a role he’ll take on two months early, as Hall plans to exit the Missouri Public Service Commission next month. North Dakota Public Service Commissioner Julie Fedorchak was elected vice president.
Transmission owners warned PJM last month that FERC inaction on the RTO’s capacity market revamp isn’t the only obstacle stalling future capacity auctions — state legislatures will likely need extra time to comply with the ruling too.
In a Sept. 4 letter addressed to the PJM Board of Managers, CEOs from PJM’s largest utilities urged the RTO to convene a meeting with stakeholders and produce a schedule that allows for time between FERC’s decision and the 2022/23 and 2023/24 Base Residual Auctions.
“Regardless of what FERC decides as to these new market rules, states will need time to react by redesigning their own clean energy programs and utility procurement programs,” said the CEOs of American Electric Power, Exelon, Public Service Enterprise Group, Dominion Energy and FirstEnergy. “This is no easy task.”
PJM submitted its proposal to create a resource-specific fixed resource requirement (FRR) in October 2018, four months after FERC ruled that its capacity market rules were not just and reasonable because they failed to address growing subsidies that the commission said are suppressing prices. (See FERC Orders PJM Capacity Market Revamp.)
The RTO made the FRR proposal as an alternative to expanding its minimum offer price rule (MOPR) to include all new and existing capacity receiving out-of-market payments, such as renewable energy credits and zero-emission credits for nuclear plants. The RTO’s MOPR currently covers only new gas-fired units.
The TOs cited comments filed with FERC from all sectors — including states, consumer advocates, load interests, suppliers, nongovernmental organizations and public power groups — that said regulatory and legislative changes will likely be required in the majority of PJM’s footprint to accommodate an FRR or expanded MOPR. Moving forward without these controls in place would further destabilize price signals and result in stranded costs, the TOs said.
“When the capacity auctions … are ultimately held, they will be most successful if they occur against a backdrop of stable and settled market rules, as well as state policies enacted in response to those rules,” the TOs’ letter concludes. “Indeed, it would be counterproductive to hold an auction when major portions of the auction framework remain in flux.”
On Sept. 27, a second cross-section of PJM members — including AEP Service Corp., Avangrid Renewables, the Illinois Citizens Utility Board, the Delaware Division of the Public Advocate, Dominion, EDP Renewables, Exelon, FirstEnergy Utilities, Natural Resources Defense Council, Nuclear Energy Institute, the D.C. Office of the People’s Counsel, PSEG and the Sierra Club — requested the RTO produce a capacity auction schedule that accommodates state and regulatory timelines, reiterating that any auction held next year would likely still be too early to factor in the impact of these policy changes.
“A rushed auction process would lead to skewed price signals that undermine economically rational behavior while reinforcing the high level of perceived (if not real) conflict that currently exists between PJM and the states,” the letter concluded.
PJM indefinitely suspended all deadlines for its upcoming BRAs pending FERC action before the end of year, when many deadlines for the 2023/24 auction would come due. (See FERC Halts PJM Capacity Auction.)
In a response to the TOs dated Sept. 12, PJM agreed to consult with stakeholders and reach out to state and regulatory commissions after a FERC order to consider next steps. Interim CEO Susan Riley noted that a “prolonged delay” undermines both investment decisions and capacity and reserve requirements.
Stakeholders, notably, say neither factor is of great concern — considering PJM’s healthy reserve margins and the fact that developers work on their own timelines — and don’t require the RTO to rush BRAs.
“At the same time, we agree that the auction must be both practical in its implementation and offer a meaningful opportunity for states to consider and pursue alternatives depending on the substance of the FERC order and their policy objectives,” Riley said. “This question of timing is well-briefed and clearly before FERC such that it may be addressed in its decision.”
PJM spokesperson Susan Buehler said Wednesday that Riley’s response applies to both stakeholder letters.
On Friday, the PJM Industrial Customer Coalition and the PJM Power Providers Group submitted a joint letter to the board pushing back against claims from other sectors that an extended delay is sustainable, saying that many resources’ lending arrangements are based on three-year forward capacity commitments and payments.
“While recipients of out-of-market payments or those resources seeking to exit the market through a FERC-sanctioned carve out may be able to better manage a capacity auction delay, those resources solely dependent on market revenues to determine their viability rely heavily on the three-year forward capacity construct to make decisions related to investments in existing units, construction of new units or retirement of uneconomic units,” the groups wrote. “The current delay of the 2019 auction is challenging many of these financial arrangements that are so critical to the overall vitality of PJM’s markets.”
ATLANTA — James Merlo, one of NERC’s most high-profile executives, abruptly left the organization last month, the latest in a series of senior staff changes under CEO Jim Robb.
Merlo, who holds a Ph.D. in applied experimental and human factors psychology, was vice president and director of reliability risk management. A West Point graduate, he joined NERC eight years ago after a 22-year career with the Army, one among a cadre of ex-military men brought into the organization by former CEO Gerry Cauley.
Since Robb joined NERC from the Western Electricity Coordinating Council in April 2018, the corporation has seen the retirement of General Counsel Charles Berardesco, and the departures of CFO and Chief Administrative Officer Scott Jones and Senior Vice President and Chief Security Officer Marcus Sachs. (See NERC Parts Ways with Chief Security Officer.) NERC’s proposed 2020 business plan reduced Robb’s direct reports to five from eight.
In a brief interview Wednesday at GridSecCon 2019, Robb declined to comment on Merlo’s departure, which occurred in late September. Employees who had been reporting to Merlo are now reporting to Senior Vice President and Chief Engineer Mark Lauby. Merlo did not return a request for comment.
Mysteriously absent from GridSecCon, the four-day conference sponsored by the Electricity Information Sharing and Analysis Center, was E-ISAC Director Bill Lawrence.
Lawrence, who was promoted to vice president and chief security officer in August 2018, was listed as a speaker on the conference’s agenda but was replaced by Robb as the presenter of the session’s opening and closing comments. No explanation was given to attendees for his absence.
“Bill’s taking some time off,” Robb said Thursday without elaborating.
Asked if he would be returning to NERC, Robb said, “I think so.”
Changing the Culture
Robb has not spoken publicly about the management changes, but he provided some insight into his management philosophy in an interview recorded by the executive search firm identifying candidates to replace Jones and Berardesco. (See NERC Leadership Search Announced.)
He said he seeks to build his executive team, and the relationship between NERC and its six regional entities, on a “foundation [of] trust.”
“I use the word ‘trust’ as a very, very important feature in terms of the way we work with the regions but also the way my executive team needs to work. Because I don’t think that’s been a hallmark of the organization in the past,” he said.
“There’s comfort; there’s disclosure; there’s honesty; and things are handled in a very trust-based way,” he explained. “When you have that, then you can deal with the conflicts that are going to naturally come up. When you can deal with that, you can generate commitment because you can explore all the outcomes and then you can focus on results … but it’s all got to start with trust.”
As a result, Robb said he will be looking at the interpersonal skills of the candidates.
“What we’re trying to de-emphasize at NERC and across the regions is leading through positional authority and more leading through inspiration and collaboration,” he said. “So, the social skills … will rank very, very highly in terms of my personal evaluation of their fit for the role and their ability to be effective going forward.
“One of the key things that’s going to be important to me and to how I judge my success here is that the organization will function as well without me as it does with me. And it requires you not to be reliant on any one personality. That’s my goal: That NERC becomes less a personality-driven organization, which I think is how people would have described it a couple years ago.”
Robb said Wednesday that “we’re making good progress” on the cultural transition. “But that’s kind of a life’s journey,” he added. “I don’t think you ever declare victory on it. But [we’ve come] a long way.”
He said NERC should be announcing a new CFO and general counsel by the end of November. “[The] interviews are moving along. We’ve got a great series of candidates,” he said.
SAN FRANCISCO – Even promoters of renewable energy are starting to worry about reliability as fossil-fuel plants retire and dispatchable renewable resources are slow to take their place.
At the American Council on Renewable Energy’s Renewable Grid Forum on Thursday, speakers talked about the need to replace gas peaker plants with batteries or other resources that can ramp up quickly on demand. Some floated the idea of installing battery storage at natural gas plants to have an instant-on solution to meet peak load. It would be less polluting, at least until the batteries ran out and the gas kicked in, they said.
About 75 people attended the event at a Hilton hotel adjacent to San Francisco’s Chinatown and just down the street from the Transamerica Pyramid.
Big utilities have joined the push for renewables, and some utility executives spoke at the meeting.
During one panel on the role of utilities in the transition to renewable energy, Frank Prager, with Xcel Energy, said the company committed in December to carbon-free energy — the first large utility to do so — but is still trying to figure out how to get there by its stated goal of 2050.
Xcel is likely to obtain an 80% reduction in carbon emissions by 2030, but then costs go through the roof, Prager said. The last 20% will be the hardest to achieve, he said.
Because wind and solar production tends to be seasonal, “you’d have to store terawatt-hours of energy for months at a time,” and that would cost trillions of dollars, he said.
Older technology such as pumped hydro could help. So could advanced nuclear generation, he said. Some developers are working on nuclear units that are much smaller than traditional plants. (See West Wrestles with Resource Adequacy, Grid Reliability.)
Excess energy might be used to create hydrogen that could then be pumped through natural gas pipelines. Fossil fuel with carbon capture and sequestration is another possibility, albeit an expensive one, he said.
Or “Mr. Fusion could come to the fore,” he said, a joking reference to the movie “Back to the Future Part II.”
Federally funded research into new technologies is needed for the nation to totally eliminate carbon emissions from electricity production, Prager and others said.
In the meantime, more utilities are joining the states and cities that have vowed to go all-green. Duke Energy, one of the nation’s largest power producers, pledged in September to go carbon-free by 2050. And PacifiCorp, another energy giant, said last week it planned by 2030 to cut its carbon emissions by 60% below 2005 levels.
“At PacifiCorp, we share a bold vision with our customers for a future where energy is delivered affordably, reliably and without greenhouse gas emissions,” the company said in a statement posted on its website.
Atlanta-based Southern Co. said in April it planned to go low-to-no carbon by 2050. NextEra Energy, which owns Florida Power and Light, said in June it would reduce carbon emissions by 40% from 2005 levels by 2025. And DTE Energy, a Detroit-based company, said in September it would seek to achieve net-zero-carbon emissions by 2050.
Julia Hamm, CEO of the Smart Electric Power Alliance (SEPA), a group that advocates for carbon-free energy by 2050, said much of the movement toward cleaner energy sources is being driven by cost; renewables, including wind and solar, are among the cheapest forms of energy available now.
But Xcel still deserves credit for its “big, bold commitment,” which prompted other energy companies to jump on the carbon-free bandwagon, she said.
“Since Xcel’s announcement last year,” Hamm said, “the announcements from utilities are coming fast and furious.”
It remains to be seen, however, whether they can meet those commitments.
FERC rejected for a third time a bid by developers to obtain transmission status and cost-based rates for a proposed $2 billion pumped storage project in CAISO (EL19-81.)
The commission dismissed Nevada Hydro’s complaint that CAISO failed to follow its Tariff in studying the Lake Elsinore Advanced Pumped Storage Project (LEAPS) in its transmission planning process.
LEAPS, which has been in development since the late 1990s, would be located about midway between Los Angeles and San Diego in Riverside County, with Lake Elsinore serving as the lower reservoir. Developers say it would produce 6,000 MWh daily, based on 12 hours of operation at the full plant capacity of 500 MW, serving the transmission systems of San Diego Gas & Electric and Southern California Edison.
In a 2008 order, FERC rejected LEAPS’ request to be treated as a transmission asset, saying it would not be appropriate to require that CAISO assume operational control of the project as requested (ER06-278).
Last year, the commission rejected the company’s request for a declaratory order finding that LEAPS is a transmission facility eligible for recovery of its costs through CAISO’s transmission access charge (TAC). The commission sided with CAISO and the California Public Utilities Commission, which had argued that Nevada Hydro’s petition was an end run around the ISO’s transmission planning process (EL18-131). (See FERC Tells LEAPS to Get in Line.)
As a result, Nevada Hydro submitted the project for CAISO’s 2018/19 transmission planning cycle. CAISO’s study of LEAPS was included in its final transmission plan on March 29, 2019, which concluded there was no need for any new transmission projects in Southern California, including LEAPS.
Illustration of proposed Lake Elsinore Advanced Pumped Storage Project | Nevada Hydro
Eight Overloads
Nevada Hydro submitted LEAPS as a transmission solution to eight thermal overloads that CAISO identified on the SDG&E system over CAISO’s 10-year planning horizon. But CAISO did not study it for those violations because the ISO had already decided on other solutions, including remedial action schemes and battery storage and demand response selected by the CPUC in its integrated resource planning (IRP) process.
Nevada Hydro complained that CAISO did not attribute any cost to the batteries, demand response or remedial action schemes, or compare them to the cost of LEAPS to determine which would be more cost-effective. CAISO said because those solutions were already in operation or under construction, they presented no new additional capital costs to consider.
Nevada Hydro also argued that CAISO failed to follow its Tariff requirements for evaluating LEAPS as an economic study request, underestimating its benefits.
The PUC; Six Cities (Anaheim, Azusa, Banning, Colton, Pasadena, and Riverside); the California Municipal Utilities Association; NextEra Energy; and the California Department of Water Resources’ State Water Project opposed Nevada Hydro’s complaint and backed CAISO’s analysis. Opponents contended that LEAPS is primarily a generation facility whose costs should be recovered through market revenues rather than the TAC.
The company did not respond to a request for comment.
Lake Elsinore | City of Lake Elsinore
No Tx Need
In its ruling, the commission said CAISO’s analysis had followed its Tariff.
“Because CAISO’s studies found no need for new transmission solutions, and because the existing solutions present no new capital costs, we find that CAISO’s Tariff does not require it to compare the cost-effectiveness of LEAPS with that of reliability solutions that are already in operation or under construction, or discuss the pros and cons of relying on existing measures that adequately ensure reliability versus investing in new transmission assets,” FERC said.
“… We continue to find that CAISO’s transmission planning process is designed in a manner that considers the full benefits of any proposed transmission solution, and that CAISO applied its process correctly with respect to its study of LEAPS,” the commission added.
The commissioners also rejected Nevada Hydro’s complaint over CAISO’s use of 4,183 MW of generation and a 2,000 MW export limit identified in the CPUC “default scenario” portfolio, saying the company should have objected during the transmission planning process. “Once the planning assumptions and study plan are adopted, those assumptions are locked in for the rest of the transmission planning cycle,” FERC said.
“We find no merit in Nevada Hydro’s assertion that CAISO abdicated its responsibilities as a regional transmission organization by adopting the CPUC default scenario portfolio. As noted by CAISO, its role is transmission planning, not resource procurement, and nothing in its Tariff requires CAISO to second guess or reverse CPUC’s resource procurement decisions or dictate what resources CPUC-jurisdictional entities can or cannot procure.”
FERC Rejects Rehearing on CAISO Capacity Market
Also last week, FERC denied rehearing on its 2018 order rejecting a request to direct CAISO to develop a capacity market (EL18-177-001).
The request had been made by CXA La Paloma, the operator of a 1,124-MW gas-fired plant in Kern County, Calif. CXA La Paloma contended California’s lack of a centralized capacity procurement was unjust and unreasonable because of falling energy prices that undermined the finances of independent generators. (See FERC Rejects Request for CAISO Capacity Market.)
On rehearing, the commission dismissed contentions that it ignored evidence and misread the law in rejecting La Paloma’s complaint. It also rebuffed requests to conduct a technical conference to examine the state’s existing resource adequacy framework. “The record evidence did not persuade the commission that additional processes, other than those [stakeholder proceedings] noted in the complaint order that were already underway, were necessary.”
