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October 31, 2024

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ISO-NE Wants to Hike its Budget by 10% in 2023

ISO-NE is proposing a roughly 10% increase in its operating budget for 2023 and the addition of more than 50 employees over the next two years as it looks to reshape the region’s electricity markets.

According to a presentation by ISO-NE CFO Robert Ludlow to NEPOOL’s Budget and Finance Subcommittee on Thursday, the grid operator’s proposed operating budget of $209 million is a more than $20 million boost (before depreciation) over that of 2022 and would require $9.475 million more in revenue.

Part of that budget bump is that the grid operator plans to add 52 full-time equivalent positions by 2024, 32 in 2023 and 20 the next year. The largest group of new jobs would be nine additions in market development, as the RTO continues to try to move forward on complex work to update the Forward Capacity Market, including with resource capacity accreditation and new day-ahead ancillary services.

ISO-NE is also proposing to add eight positions to its information and cybersecurity office, five for system planning, and two each in participant relations, advanced technology solutions, system operations and market administration, external affairs and HR.

And it’s budgeting more — $8.4 million in total — for employee raises and benefit increases, plus recruiting, retention and succession planning.

The grid operator’s 2023 capital budget is $33.5 million, a $7 million increase over those of the last few years, driven by the next generation markets project, other market and reliability initiatives, cybersecurity enhancements, and information technology and infrastructure replacements.

The budget finds $3.4 million in savings, including lower salary rates from turnover and retirements, less building maintenance, fewer software licensing costs and more.

Because ISO-NE is funded by fees from market participants and ratepayers, the budget is scrutinized closely by consumer advocates and state officials. The RTO is currently in the process of running the budget by state agencies and planning to ask for a NEPOOL Participants Committee vote in October, shortly followed by a Board of Directors vote and FERC filing.

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FERC Rejects PJM’s Reserve Deployment Proposal

FERC on Monday rejected PJM’s proposal to change how it handles synchronized reserve events, saying it would likely result in higher prices and lead the RTO to procuring more energy than the system actually needs during emergencies (ER22-1200).

Called Intelligent Reserve Deployment (IRD), PJM’s proposed construct would have it use a real-time security-constrained economic dispatch (RT SCED) case that simulates the loss of the largest generation unit on its grid during a synchronized reserve event. Such events can be caused by the loss of generation, loss of transmission or sudden increase in load.

Currently, PJM responds to these emergencies by issuing an “all-call” message to all market participants to deploy their available resources. The RTO argued that IRD would be more efficient and that, by using RT SCED, it would better align prices with actual grid conditions and trigger resource-specific responses.

But FERC was unpersuaded, ruling 4-1 that IRD “fails to model actual system conditions.

“It therefore is likely to result in artificially inflated prices and thus prevent PJM from achieving a least-cost dispatch solution to address synchronized reserve events, which could in turn produce a misalignment between prices and actual system conditions.”

IRD would simulate the loss of the generator by effectively increasing the load forecast by the equivalent capacity. Thus, FERC found, it would not lead to accurate dispatch, as most reserve events are likely to be smaller in nature.

“IRD would result in PJM setting prices as though the largest contingency had occurred, and then immediately procure additional reserves accordingly, without regard for the size and location of the actual system event,” the commission said. Even if the emergency were the result of the largest contingency, “the IRD SCED case might not be representative of actual system conditions if the contingency event occurs near a constraint or within a reserve sub-zone … because IRD would model an RTO-level increase in load,” FERC said.

PJM filed its proposal in March under Section 205 of the Federal Power Act, after it received final stakeholder approval in January, though with 18 objections. (See “Consent Agenda,” PJM MRC/MC Briefs: Jan. 26, 2022.) FERC acknowledged that the current all-call approach could be improved upon, but the RTO “must show that any such proposed methodology produces just and reasonable rates.”

FERC agreed with arguments by the RTO’s Independent Market Monitor and the PJM Industrial Customer Coalition that the proposal would result in unjustly higher prices. But it also noted that, in response to their protests, PJM had acknowledged that the price resulting from IRD cases “is not perfect,” though it emphasized that it would be more accurate than under the all-call approach.

“Even if that characterization were true, that does not render this particular proposal to use the largest contingency in the IRD case just and reasonable,” the commission said.

Danly Dissent

Commissioner James Danly dissented, arguing that PJM “easily met its Section 205 burden” and rejecting the majority’s conclusion that IRD would “artificially inflate prices.”

“I see nothing wrong with modeling the single largest reliability contingency during a reserve shortage, for example, when the system is dangerously exposed to a subsequent reliability event,” Danly said.

Danly argued that IRD would clearly be an improvement over the all-call approach, which he said “is essentially an email blast” that “apparently is routinely ignored by resources not subject to nonperformance penalties. It does not take an engineer to identify a legitimate reliability risk here.”

“I would not reject a clear reliability enhancement merely because it results in potentially higher (albeit more efficient) prices,” he said. “FPA Section 205 contemplates broad discretion for utilities to grapple with challenges and opportunities as they see fit. This filing easily fits within the range of acceptable filings.”

He concluded that, despite rejecting the proposal, “we at the commission will enthusiastically join the throngs blaming PJM if, down the road, it suffers a blackout caused by back-to-back reliability events.”

The majority responded to Danly’s dissent by noting that PJM acknowledged that the system would remain reliable without IRD. It also argued that part of Danly’s argument was apparently based on the fact that Tier 1 synchronized reserve resources are not subject to nonperformance penalties, but it noted that the commission had already approved PJM consolidating Tier 1 and 2 resources into a single product, which will be subject to penalties and go into effect Oct. 1. (See FERC Approves PJM Reserve Market Overhaul.)

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ERCOT Names NiSource’s Vegas as New CEO

AUSTIN, Texas — ERCOT announced Tuesday that it has selected Pablo Vegas, a senior executive with Indiana-based utility NiSource, as its next CEO.

Vegas, currently an executive vice president with the company and group president of NiSource Utilities, will join the Texas grid operator on Oct. 1. He will replace interim CEO Brad Jones, whose 90-day temporary gig has stretched into a 16-month assignment.

The announcement came during the Board of Directors’ bimonthly meeting and was quickly ratified by the Texas Public Utility Commission.

Vegas will be expected to guide ERCOT as it continues to make changes following the February 2021 winter storm that nearly brought the Texas Interconnection to its knees. A massive loss of generation led to dayslong outages that resulted in hundreds of deaths and billions of dollars in damages.

Pablo Vegas (NiSource) FI.jpgPablo Vegas, NiSource | NiSource

“With Pablo, we’re getting the leader we’ve been looking for: extensive experience with regulated utilities; a demonstrated record of managing a system of diverse energy resources; and most importantly, unwavering commitment to reliability,” board Chair Paul Foster said after breaking the news. “With this unanimous vote, it is clear that this board believes we have found an exceptional executive who can successfully lead this organization.”

The board approved Vegas’ selection and compensation package during an executive session Monday. The announcement was made at the start of the board meeting Tuesday as it became apparent to the directors that the news had been leaking out and represented “a risk to the [employment] agreement.” One market insider said they had first heard Vegas’ name last Thursday.

NiSource is one of the largest fully regulated utility companies in the U.S., serving approximately 3.2 million natural gas customers and 500,000 electric customers across six states through its Columbia Gas and Northern Indiana Public Service Co. brands.

Vegas, who was only promoted to his present position on July 1, signed his contract Monday. He was not in Austin on Tuesday or available for comment. ERCOT directors and staff declined to comment.

“I’m excited to return to Texas both personally and professionally,” Vegas said in a statement. “This is a once-in-a-lifetime opportunity to lead an exceptional organization of people and make a positive impact on millions of Texans.”

Before joining NiSource in 2016, Vegas spent 11 years with American Electric Power. He served as president and COO of both AEP Texas, for two years, and AEP Ohio. Vegas has a bachelor’s degree in mechanical engineering from the University of Michigan and held senior leadership positions with Andersen Consulting and other firms before joining the utility industry.

Judith Talavera, who currently holds Vegas’ titles for AEP Texas, said his time in the state “gives him a unique understanding” about the ERCOT system’s strengths and weaknesses.

“His experience in Texas and his leadership positions at AEP Ohio and NiSource will serve him well in his new role as ERCOT CEO. We look forward to working with him,” Talavera said in an email to RTO Insider.

“It doesn’t hurt that this isn’t his first rodeo in Texas,” Foster told the board. “Pablo knows our current market; he knows the incredible progress we’ve made in the last year implementing landmark reforms; and he knows how to turn the challenges we face into opportunities to strengthen the competitive market in Texas.”

“He has been an invaluable member of our leadership team, and I along with the entire NiSource community will miss working with Pablo, and we wish him the best in his new role at ERCOT,” NiSource CEO Lloyd Yates said in a press release.

Vegas’ hiring comes after several sources told a Texas newspaper that Gov. Greg Abbott stepped in to reject an earlier selection of former CAISO CEO Steve Berberich. (See ERCOT Could Name New CEO this Week.)

According to his employment contract, Vegas will earn a base salary of $990,000 and a one-time lump sum payment of $247,500 on or before Dec. 31. He will also receive make-whole payments of $6.68 million through 2027, when his contract ends. Beginning next year, Vegas will be eligible for incentive payments that could equal his base salary, assuming he meets key performance indicators.

Former ERCOT CEO Bill Magness, who was fired in March 2021 following the winter storm, disclosed during testimony before the Texas Legislature last year that his annual salary was $803,000. Jones’ annual salary is $500,000, and he is a due a one-time lump sum of $169,640 when he receives his final paycheck.

South Texas Electric Cooperative’s Clif Lange, chair of ERCOT’s Technical Advisory Committee, said the group looks forward to working closely with Vegas when he takes over.

“He faces some very big challenges as he transitions into the role, with a number of initiatives already started but with many still ahead,” he said, referring to the second phase of ERCOT’s market design. “I’m optimistic that he’ll be able to lead ERCOT successfully in implementing those.”

Director Bill Flores led the selection committee in what was termed an “exhaustive” nationwide search. He said the group identified 107 candidates and interviewed 21.

The directors, ERCOT staff and stakeholders saluted Jones with a standing ovation after the announcement was made.

“Twenty-six million Texans owe you a real debt of gratitude for everything you and the team have done to persevere through the challenges faced with record heat and cold winters,” Flores said.

A smiling Jones pointed to his grin as he greeted well-wishers during the meeting’s first break. He will spend October helping Vegas transition into his new position before resuming a retirement that was interrupted by the winter storm.

“Brad stepped in as our interim CEO during a very challenging time and was unquestionably the leader ERCOT needed at a most difficult time,” Foster said. “He’s also stayed much longer than originally anticipated.”

“Hopefully, his next endeavor includes an enjoyable and relaxing retirement, although I will bet that he will remain engaged in the electric industry. It’s in his blood,” Lange said. “He’s faced a monumental task in overseeing a significant overhaul of ERCOT’s priorities, and while it’s not always been popular, he’s been very successful in navigating those changes.”

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Diablo Canyon Extension Effort Gears up

The movement to keep California’s last nuclear plant operating beyond its impending retirement has gained new momentum with the prospect of billions of dollars in state and federal funding, support from Gov. Gavin Newsom, and the clearest indication yet that plant owner Pacific Gas and Electric (NYSE:PCG) could go along with the plan.

PG&E has been planning to shut down its 2.2-GW Diablo Canyon nuclear power plant by 2025, a move sought by anti-nuclear activists concerned with seismic safety and by PG&E, largely for economic reasons. In 2016, the state’s largest utility signed an agreement with environmental, labor and anti-nuclear groups to close the plant on California’s Central Coast rather than invest billions of dollars in environmental and safety upgrades.

Now, however, proponents see the continued operation of Diablo Canyon — the state’s largest generator producing about 8.5% of total capacity — as vital to ensuring grid reliability during the state’s transition to 100% clean energy by 2045. Energy emergencies during the past two summers and the likelihood of continued shortfalls caused by wildfires, drought and extreme heat have prompted some who supported the closure to reconsider, including the governor.

Newsom’s office circulated draft legislation Thursday that would lend PG&E up to $1.4 billion in a forgivable loan to keep Diablo Canyon open for an additional five to 10 years beyond its planned retirement date.

“It is a very difficult decision, and it’s a last resort,” Ana Matosantos, Newsom’s cabinet secretary, said in a workshop Friday hosted by the California Energy Commission and CAISO. Supply-and-demand forecasts based on historical data “are not necessarily reflecting our real-term reality and the speed at which the impacts of climate change are being experienced by our people and by our energy system,” she said.

In extreme scenarios, cumulative disruptions from weather and fire could leave the state 7,000 MW short this summer and up to 10,000 MW short by 2025, CEC analysts said in May. The gap could be as little as 1,700 MW this summer and 1,800 MW in 2025 without cumulative crises, they said. (See Heat, Fire and Supply Chain Woes Threaten Calif. Reliability.)

In addition, peak summer demand has shifted later in the day, after solar ramps down on hot evenings, resulting in shortfalls, and demand is expected to increase as millions of electrical vehicles replace gas-powered cars and trucks in coming years.

“The net of all of these pieces is that we are behind where we need to be in bringing our clean resources online to ensure that we can retire these [other] resources,” Matosantos said. “And so, we are meeting to have the very difficult conversation around an extension [of Diablo Canyon], the terms and the conditions under which an extension would be done, and the duration of any extension to make it as short as possible.”

Funding Possible

The availability of billions of dollars in federal aid could make an extension more feasible.

Matosantos wrote to U.S. Energy Secretary Jennifer Granholm in May, asking that the Department of Energy amend its eligibility criteria for the Biden administration’s $6 billion Civil Nuclear Credit Program (CNC), funded under November’s Infrastructure Investment and Jobs Act. The program is meant to assist nuclear plants at risk of closure for economic reasons.

In an April guidance, DOE had said CNC funding is for nuclear plants that participate in competitive energy markets and do not recover more than 50% of their costs from cost-of-service ratemaking. PG&E recovers its Diablo Canyon costs from customers under rate cases approved by the California Public Utilities Commission and would not qualify for CNC funding under that interpretation.

Matosantos requested that DOE’s guidance be changed to exclude the cost-of-service requirement. The department approved the change on June 30 and extended the application deadline for the first round of CNC funding to Sept. 6.

PG&E has said it will apply for the funding. Company CEO Patti Poppe said in a July 28 earnings call that the company was looking to keep Diablo Canyon open — the strongest company statement of its kind — but warned parties that the “clock is ticking” on the time needed to switch from decommissioning the plant by 2025 to operating it through 2035.

State and federal entities, including the U.S. Nuclear Regulatory Commission and the California State Legislature, will need to weigh in to make that happen in an accelerated time frame.

State Sen. John Laird, who represents the district containing Diablo Canyon, said at Friday’s workshop that the speed at which the plant might reverse course would contrast sharply with the effort to close the plant, which took years.

“Endless hours and millions of dollars have been used to plan for the plant’s closure and coordinate with local state and regulatory bodies on the decommissioning effort,” Laird said.

Questions about cost, safety and environmental impacts, including nuclear waste storage, remain unanswered, he said. Laird also questioned the potential effects of keeping the plant open on offshore wind development. Floating wind turbines off the coast near Diablo Canyon, in the planned Morro Bay wind energy area, are expected to connect to CAISO’s grid using transmission lines that now serve the plant.

“I don’t see a pathway to Diablo Canyon’s continued operation unless each of these elements is addressed,” Laird said. “No proposal can be complete without that.”

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Members Near Vote Over PJM, IMM Black Start Fuel Requirements

VALLEY FORGE, Pa. — Capping four years of discussions and analysis, PJM held a first read of proposed fuel assurance rules for black start resources (BSRs) at the Market Implementation and Operating committee meetings Wednesday and Thursday.

PJM has considered fuel supply capabilities along with other technical, operational and cost factors in awarding black start contracts in the past. In 2017, the RTO increased the weighting of fuel assurance in its evaluation of responses to requests for proposals. But current rules have no fuel assurance requirement other than an existing tariff provision requiring black start units to maintain enough fuel for 16 hours of run time.

PJM’s Janell Fabiano said work on the black start proposals — which included a two-year “hiatus” in stakeholder discussions while PJM conducted analyses of restoration times, costs and benefits, and gas supply risks — was an “epic process.”

In the 2018 problem statement launching the effort, PJM said only about half of the units in its black start fleet were fuel assured “through dual-fuel capability, on-site fuel storage or multiple gas pipeline connections.”

The committees heard presentations on two competing proposals, one from the Independent Market Monitor and a second cosponsored by PJM, Brookfield Renewable and the D.C. Office of the People’s Counsel.

Only 23% of stakeholders supported the Monitor’s proposal in polling in June. Nearly three-quarters of stakeholders said they supported PJM’s proposal before it was combined with one from Brookfield and the OPC, which had received 37% support.

PJM Package

The PJM package would select black start sites based on their fuel assurance, giving top preference to units with on-site fuel storage (e.g., dual fuel), followed by those connected to multiple pipelines and then gas-only sites connected to a single source fed directly from a gas supply basin or gathering system ahead of an interstate pipeline.

After that, PJM ranks fuel-assured hydro units (pump storage and run-of-river), followed by fuel-assured intermittent or hybrid sites. The last choice would be at least two gas-only sites in a transmission owner’s zone connected to two separate interstate gas pipelines.

Additional black start units would be solicited for eight “high-impact” sites in which incremental restoration time would be 10 hours or longer with the loss of a non-fuel-assured black start site.

Mitigation of the eight sites in five TO zones would add $28.2 million to the current annual black start cost of $68.2 million, a 41% jump, according to PJM.

IMM Package

The IMM said existing BSRs lacking fuel assurance should correct the problem or have their black start status terminated, with penalties for nonperformance.

The Monitor also would require predefined emission and effluent waivers to accommodate operations during restoration rather than PJM’s proposal that generators use their “best efforts” to obtain permit modifications or waivers.

For dual-fuel resources, the Monitor would require testing of both fuels annually, including a demonstration of the ability to switch between fuels. PJM proposes separate testing for each fuel in the same year. The IMM also would require concurrent annual tests of all BSRs connected to the same fuel source. PJM would not.

PJM would increase the “Z factor” incentive from 10% to 20% for fuel-assured resources selected via the RFP. PJM said the change would cost $436,000 annually.

The IMM would keep the base formula rate incentive factor for such units at 10%. The incentive is multiplied by the sum of fixed and variable black start service costs plus training and fuel storage costs.

The Monitor would also end PJM’s current practice of allowing transmission owners to provide black start service under a “backstop” process following two failed RFPs. “TOs should not own generation,” the Monitor said.

The IMM also opposed PJM’s proposal to allow intermittent resources to seek black start contracts. The Monitor said intermittent resources, other than run-of-river hydro, should not be considered BSRs because they cannot be assured of being available when needed.

PJM’s Tom Hauske said the RTO wanted to allow intermittent resources with storage to offer as black start and to anticipate future technologies. “It’s not going to be easy” for renewables to qualify, he acknowledged.

In a presentation of the IMM’s proposal, Monitoring Analytics President Joe Bowring took exception to the fact that PJM had decided not to impose penalties on intermittent resources that registered as fuel-assured BSRs but failed to meet the new rules, saying that this was “discriminatory” and “doesn’t make any sense.”

PJM said the penalties would be unfair to intermittent resources because the RTO would be responsible for calculating confidence levels for such generators.

Generators are responsible for their own performance, regardless of whether PJM defines the performance standard, Bowring said.

Zonal vs. Regional Plan

Bowring also challenged PJM’s plan to award black start sites, and allocate their costs, by TO zone.

“From a PJM perspective, the zonal approach is the correct approach,” said Dan Bennett, who presented PJM’s proposal. “No one knows a zone more than the transmission operator. They are the right people to be managing this.”

Bowring said TO zones are anachronisms under PJM’s regional management of the grid and that the RTO should take advantage of cross-zonal benefits.

“The fact that TOs can do it is irrelevant,” Bowring said. “There is no magic to zones. Zones are arbitrary. PJM has unfortunately taken the position that TOs are more capable than itself. It’s PJM’s responsibility to do it.”

Greg Poulos, executive director of the Consumer Advocates of the PJM States, said some advocates are not convinced there is a need for black start units in every TO zone. “We are interconnected, unlike ERCOT,” Poulos said. “We do have the ability to have other resources help us.”

Impact on Existing Resources

Stakeholders voiced confusion and concern over the proposed changes, asking for clarification on how they would impact current BSRs that do not register as being fuel assured.

Paul Sotkiewicz of E-Cubed Policy Associates summarized many of these concerns when asking whether the process would be “voluntary” and whether it “would negatively impact BSRs that do not officially register as being fuel-assured.”

PJM responded that the new rules would not impact existing BSRs and were a voluntary process that sought to give additional compensation to eligible generators. Bennett encouraged stakeholders to continue providing feedback or suggestions that would make the packages “stronger because of teamwork.”

The BSR discussions exceeded the allotted time in both the MIC and OC meetings. PJM has scheduled a special meeting for Aug. 25 on the issue. PJM is targeting a filing to FERC in December and an RFP in April 2023.

Dual Votes

Because both the MIC and OC took part in discussions, both will be involved in voting on the two proposals, PJM’s Fabiano said. Voting will open after the Sept. 8 OC meeting and close at 5 p.m. ET on Sept. 15. Only one representative per voting member may participate; if different representatives vote at the MIC and OC, PJM will consolidate the responses and validate one response per member.

Poulos thanked PJM for its work helping the advocates understand the cost-benefit of the fuel incentives. PJM used a range of probabilities of a coincident blackout and fuel delivery failure and a range of values of lost load to calculate the increase in the expected cost that could result if a black start site were unavailable because of fuel failure.

“I don’t think they’re all going to be for it, but I certainly think there’s going to be more support … than there would have been without PJM’s work,” Poulos said of his members.

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Washington’s Tri-Cities Lobbies Granholm for Clean Energy Funding

RICHLAND, Wash. — Business and political officials from southeastern Washington lobbied Energy Secretary Jennifer Granholm for a piece of the Biden administration’s clean energy spending last week during her tours of the Pacific Northwest National Laboratory and the nearby Hanford nuclear site.

Leaders from Washington’s Tri-Cities — Richland, Kennewick and Pasco — said the region would be a good place to nurture a center of a clean energy industry.

Washington state officials also want a piece of the $8 billion the federal government plans to award for regional hydrogen hub projects.

“Whether that will happen [in Washington]? I don’t know,” said U.S. Sen. Maria Cantwell (D-Wash.), who joined Granholm during Thursday’s visit to PNNL, where they were briefed on the lab’s clean energy technology projects.

Granholm 2022-08-12 (RTO Insider LLC) FI.jpgEnergy Secretary Jennifer Granholm tours the Hanford Nuclear Site’s B Reactor, which produced the plutonium used in the atomic bomb dropped on Nagasaki, Japan. | © RTO Insider LLC

Granholm, who visited the Hanford nuclear reservation on Friday, said it will be months before the Department Energy decides how to divide up the $8 billion. DOE expects to receive more than 100 proposals to create regional hydrogen production and distribution hubs by September, when the agency will begin winnowing the proposals to four to eight projects. Granholm declined to speculate on how long that selection process will take.

Granholm’s visit came just before the House on Friday approved the Inflation Reduction Act, which includes a long list of clean energy measures. (See What’s in the Inflation Reduction Act, Part 1.)

Implementing the law will be a huge task, Granholm said. “It’s deployment, deployment, deployment of clean energy.”

Granholm said the administration could seek additional legislation in the next couple years, such as tax credits for improvements to the nation’s power grid. “We are always trying to perfect things,” she said.

Washington’s Hydrogen Efforts

Washington’s first hydrogen production plant is expected to go online in central Washington’s East Wenatchee in mid-2023. The Port of Seattle is studying whether it wants to get into the hydrogen fuel business. Paccar, a truck manufacturer in the Seattle suburb of Renton, is testing 10 hydrogen-fueled semitrucks in Los Angeles. And public transit in Chehalis — south of Olympia — expects to start running hydrogen-fueled buses this year.

Fortescue Future Industries of East Perth, Australia, announced its intentions to build a hydrogen production facility next to the TransAlta coal-fired power plant in Centralia, also south of Olympia. So far, Fortescue has not announced any details on that plan. The TransAlta plant is due to close in 2025.

Gov. Jay Inslee has led the state’s lobbying efforts for the hydrogen funding, citing Washington’s intense efforts to shrink its carbon footprint.

The Washington legislature made several decisions this past session to support these efforts. Lawmakers allocated $2 million to lobby for hydrogen projects. They created an office of renewable fuels within the Washington Department of Commerce and some new tax breaks for renewable energy projects.

In 2021, the global hydrogen market was estimated at $130 billion and was expected to expand 6.4% annually, according to a report by Grand View Research, a San Francisco marketing research firm. And a February 2022 report by Goldman Sachs said, “Our global …   hydrogen scenarios all show stellar growth of the clean hydrogen economy.”

‘This is the Place’

Hanford and Tri-Cities leaders also lobbied Granholm and Cantwell hard on the concept of a clean energy development center in  the southeastern high-tech community. The Tri-Cities has pushed on the energy center concept for roughly a quarter of a century, with sporadic progress.

Karl Dye, executive director of the Tri-Cities Industrial Development Council, and others noted the Tri-Cities are within 30 miles of a nuclear power plant, three hydroelectric dams, several proposed solar panel farms and some wind turbines. “We have some of the cheapest, greenest energy in the country,” Dye said.

“If you want a good demonstration on if this could work? Here. This is the place,” said Bob Schuetz, executive director of Energy Northwest, which operates the 1,200-MW Columbia Generating Station north of Richland. Energy Northwest also has a 4-MW solar farm in northern Richland and plans to start building a 145-MW solar farm near the Columbia nuclear plant in January 2023, with completion expected in early 2024.

Another six solar panel farms are being developed in the Yakima River Valley 20 to 40 miles west and northwest of the Tri-Cities.

However, a wind farm proposed for the hills just south of the Tri-Cities has drawn controversy because many Tri-Citians don’t want turbines in their views of the southern skyline.

Energy Northwest is in discussions with small modular reactor developers about getting involved with one of those projects.

“I like this notion of switching from [nuclear] cleanup to power,” Granholm said.

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Access to Meter Data Holding Back Residential DR, CSPs Say

VALLEY FORGE, Pa. — Demand response programs for residential customers and small businesses are being hampered by difficulties accessing interval meter data, CPower Energy Management said in a proposed problem/opportunity statement presented to PJM’s Market Implementation Committee Aug. 10.

PJM allows the use of sampling to estimate demand response participation for customers lacking interval meters — also known as smart meters — but requires the use of such meter data for customers that have them.

For smart meter-equipped residential customers serving as annual demand response resources, PJM requires not only usage data for settlements and compliance during events and tests, but data from two prior delivery years to establish a winter peak load and peak load contribution (PLC) to set baselines.

Ken Schisler of CPower said electric distribution companies (EDCs) have made it difficult and expensive for curtailment service providers (CSPs) to obtain the data. In some cases, he said, EDCs lack the information. In other cases, the data is cost prohibitive to obtain for small loads.

The introduction of smart meters has not resulted in the expected increase in DR participation, Schisler said. Demand response is an “underdeveloped resource in PJM,” he said. “I submit one reason for that is data access.”

Cleared demand response capacity has dropped by almost half since peaking at 14,833 MW in delivery year 2015/16. In June’s Base Residual Auction, cleared DR totaled only 8,096 MW.

Paul Sotkiewicz of E-Cubed Policy Associates questioned the need for a rule change. “It doesn’t sound like an insurmountable problem,” he said. “… I’m wondering if this is a solution in search of a problem.”

But Aaron Breidenbaugh of Centrica Business Solutions said his company shared CPower’s concerns. The cost of obtaining meter data is not as big a concern for large customers but “creates significantly higher costs of customer acquisition” for small loads, he said.

CPower’s issue charge proposes that stakeholders consider additional use of sampling as an alternative to data from every small customer.

“Do we need data for every single meter?” Schisler asked. “… Is the juice worth the squeeze?”

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IMM Report Notes Rising Fuel, Congestion Costs in PJM

Real-time load-weighted LMPs averaged $67.77/MWh in the first six months of 2022, a 121.3% increase from a year earlier and the largest such spike in the first two quarters since the PJM markets launched in 1999, the Independent Market Monitor reported in its State of the Market report for the second quarter.

The total price of wholesale power increased almost 70% to $95.93/MWh for the first six months of 2022, with energy, capacity and transmission charges representing 98% of the total. Transmission costs per megawatt-hour have exceeded capacity costs since the third quarter of 2019, the Monitor reported.

Almost half of the $37.15/MWh increase was a result of higher fuel and emission costs, with coal and natural gas prices doubling in eastern PJM, the Monitor said. Average real-time loads also were up, increasing by 1.9% to 87,616 MWh.

Congestion costs — LMP price differences resulting from binding transmission constraints — increased by almost $792 million (223.7%) over the same period. Only 31.5% of congestion costs paid by customers for the 2021/22 planning period ending in May was returned to them through the auction revenue rights (ARRs) and self-scheduled financial transmission rights revenues offset, the lowest offset since ARRs were implemented, the Monitor said.

“Congestion belongs to customers and should be returned to customers,” the Monitor said. “The goal of the FTR market design should be to ensure that customers have the rights to 100% of the congestion that customers pay.”

Generation from coal units dropped 6.4% in the first six months of 2022, while natural gas-fired generation increased by 5.2%.

Energy uplift charges increased by $2.8 million (3.6%) in the first half of the year to $82.1 million.

The Monitor offered three new recommendations in the Q2 report:

  • PJM, rather than the unit owner, should select the time and day that a unit undergoes net capability verification testing, and the timing should not be communicated in advance to the unit owner. The tests, required to demonstrate that a unit has the installed capacity claimed, are submitted for the summer and winter testing periods. The Monitor also said PJM should require actual seasonal tests and that the ambient conditions under which the tests are performed should be defined. PJM currently permits the use of summer test data adjusted for ambient winter conditions in lieu of actual winter test data.
  • If energy efficiency resources remain in the capacity market, PJM should codify eligibility requirements for claiming capacity rights and institute a registration system to track and document such claims. The Monitor contends EE should not be included on the supply side of the capacity market because PJM’s load forecasts now account for future EE.
  • PJM should use a nodal approach for distributed energy resources participating in RTO markets. “The PJM market is a nodal market because nodal markets provide efficient price signals to resources in an economically dispatched, security-constrained market,” the Monitor said. “Allowing DER aggregation across nodes is not necessary and would distort market signals indicating where capacity and energy are needed.”
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SPP Briefs: Week of Aug. 8, 2022

RTO, SaskPower Agree to Expand Interconnection’s Capacity

Canadian utility SaskPower said on Wednesday that it has signed a 20-year agreement with SPP to more than quadruple transmission capacity between the province of Saskatchewan and the U.S., effective 2027.

The utility and SPP will expand the 150-MW tie line that connects them to 650 MW. SaskPower said expanding the transmission capacity between the two countries will also improve reliability on its side of the border and allow the utility to export excess power to SPP, creating revenue opportunities.

“Access to this large market ensures reliable energy is available to Saskatchewan to support our own generating facilities,” SaskPower CEO Rupen Pandya said. “This will help to manage the integration of more intermittent renewable power such as wind and solar while keeping costs as low as possible for customers.”

SaskPower Footprint (SaskPower) Content.jpgSaskPower’s footprint has three ties with the U.S. | SaskPower

SaskPower will build the necessary transmission facilities on its side of the border over the next five years, and SPP will be responsible for construction on its side.

SPP has been making international transactions with SaskPower since 2015, thanks to Canadian interconnections that came when the Integrated System joined the RTO. (See SPP, SaskPower Make First International Trade.)

Clements Dissents on Accreditation Order

After two deficiency notices, FERC has approved SPP’s request to add capacity accreditation methodology provisions for wind and solar resources to its business practices and planning criteria. The RTO now determines the accredited capacity of qualified run-of-river hydroelectric, wind and solar resources based on historical performance, effective Feb. 15, 2022 (ER22-379).

The commission in its Aug. 5 order directed SPP to make a compliance filing within 30 days. The RTO filed its request in November 2021.

Commissioner Allison Clements partially dissented from the order, tweeting last week that she did so on the condition that SPP submit revised tariff compliance records. She said the RTO “should have submitted tariff revisions that explain what its proposal actually is.”

“Granted, the majority agrees that SPP’s proposal falls short of the commission’s rule of reason,” Clements wrote. “But they take it on faith that SPP will submit satisfactory tariff revisions on compliance, without knowing what those revisions would actually say. I cannot conclude that a tariff change is just and reasonable based solely on its general description.”

M2M Settlements up to $341.9M

SPP staff briefed the Seams Advisory Group on Friday on three months of market-to-market (M2M) transactions that brought the settlement accruals in its favor with MISO to $341.9 million.

More than half of the three months of transactions came in April at $26.5 million, the third-highest month between the seams neighbors. Settlements in May and June pushed the three-month total to $50.6 million. Permanent and temporary flowgates were binding for 5,907 hours during the three months.

M2M settlements for the redispatch of market flows around congested flowgates have now been in SPP’s favor for 16 straight months and 31 of the last 33. The RTOs began the process in 2015.

“The weather wasn’t too crazy,” SPP’s Jack Williamson told SAG. “We’re constantly breaking new peak records all the time. We’re seeing more and more wind on the system.”

Staff also told the stakeholder group that it is developing its first emergency energy exchange agreement with another seams neighbor, Missouri-based Associated Electric Cooperative Inc. The joint operating agreement does not currently have provisions for energy exchanges during energy emergencies, but SPP has similar arrangements with SaskPower, MISO and Public Service Company of Colorado.

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PJM Planning Committee Briefs: Aug. 9, 2022

PJM to Make Designated Entity Agreement Filing ‘Shortly’

VALLEY FORGE, Pa. — PJM attorney Pauline Foley provided a brief update on the RTO’s plans to make a Federal Power Act Section 206 filing asserting that the Operating Agreement’s provisions on designated entity agreements (DEAs) are unjust and unreasonable.

Foley said the RTO will assert that the OA’s references to DEAs are “overly broad and imprecise.”

PJM “anticipates making the filing shortly,” she said. “I don’t have an exact date.”

News of PJM’s planned filing prompted the cancellation of scheduled votes on competing issue charges on the matter at the July 27 Markets and Reliability Committee and Members Committee meetings. (See “Application of Designated Entity Agreement,” PJM MRC/MC Briefs: July 27, 2022.)

On July 26, a group of load-side stakeholders beat PJM to FERC, filing a complaint asking the commission to force the RTO to require incumbent transmission owners to sign DEAs on “immediate need” projects. The complainants contended the RTO has violated the OA by refusing to do so. (See PJM Challenged on Oversight of ‘Immediate Need’ Tx Projects.)

Generator Deliverability Test Update

Most stakeholders urged PJM to delay a vote on changes to generation deliverability testing procedures until the rules for effective load-carrying capability (ELCC) capacity interconnection rights (CIRs) are considered.

The deliverability test ensures the transmission system can transmit its generating capacity at summer peak load as well as under light load and winter conditions. The proposed changes are in response to increasing system variability caused by growing renewable penetration. (See “Generator Deliverability Education,” PJM Planning Committee Briefs: July 12, 2022.)

CIRs set an upper bound on the amount of installed capacity attributed to a generation capacity resource. ELCC resources such as renewables cannot run at their maximum output for more than 24 hours.

“It could be independent and should be independent,” Exelon’s Pulin Shah said of the two processes.

But other stakeholders — including Apex Clean Energy Group, LS Power, the PJM Public Power Coalition, Old Dominion Electric Cooperative, and economists Paul Sotkiewicz and Roy Shanker — said the issues should be considered together.

“I don’t see how it can be done separately,” said Shanker. “You could have a whole lot of [generation] that’s approved but not deliverable because of changes that happen two months later.”

“They need to go hand in hand,” said Sotkiewicz, of E-Cubed Policy Associates.

Carl Johnson, representing the PJM Public Power Coalition, said coupling the issues “creates the least uncertainty.”

PJM’s Jonathan Kern said the RTO is proposing to merge summer, winter and light load deliverability testing methods.

In June, the PC’s special session on CIRs for ELCCs discussed competing proposals from PJM, LS Power, Global Infrastructure Partners’ Eolian subsidiary and Sotkiewicz. The group originally planned a final review in July, but the meeting was postponed until late August to allow for more offline discussions to forge compromises. (See “‘Time to Get Involved’ in Capacity Interconnection Rights for ELCC Resources,” PJM Planning Committee Briefs: July 12, 2022.) New rules would be implemented for the 2025/26 Base Residual Auction.

The generator deliverability test changes would be made in Manuals 14A and 14B. They would add a new block dispatch approach to dispatch cases. To ensure a realistic dispatch, the base case would not allow any locational deliverability area (LDA) to import more power than their capacity emergency transfer objective (CETO).

The light load period, currently 12 to 5 a.m., would be redefined to include daytime hours from 10 a.m. to 3 p.m. where the RTO’s coincident peak load is between 40 and 60% of the annual peak. The default light load temperature would be 59 degrees Fahrenheit.

The new rules also will include more wind and solar in base case dispatches, with fixed solar rising from 38% to 47 to 55% of nameplate capacity in summer. Onshore wind would increase from 13% to 16 to 20%, and offshore wind would jump from 30% to 33 to 38%.

PJM wants stakeholder approval of the deliverability changes by December so they can take effect for the 2028 Regional Transmission Expansion Plan.

Load Model Selection Endorsed

Members unanimously endorsed PJM’s proposal to use a 2002-2012 load model for the 2022 Reserve Requirement Study.

PJM’s Patricio Rocha Garrido said the RTO changed its recommendation from the 2000-2010 model after discovering that a Monte Carlo simulation of the model “distorts the total distribution.”

The model selected is based on an analytical method rather than Monte Carlo sampling, he said. “At the 97th percentile and above, the Monte Carlo is not doing a good job.”

Sotkiewicz asked PJM to provide written language describing its algorithms “to avoid … confusion.”