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October 3, 2024

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SoCalGas System Still ‘Impaired’ but Winter Outlook Improves

Southern California Gas’ system remains “impaired,” but the risk of service reductions is lower than in previous years because a warm winter forecast could reduce demand for gas-fired electric generation, the California Energy Commission heard Wednesday.

During a joint workshop with the California Public Utilities Commission, Energy Commission staff said two key pipelines are operating at reduced capacity, including one pipeline that ruptured in 2017. An El Paso Natural Gas mainline that ruptured last year south of Phoenix is shut down, limiting supply from the Permian Basin. And storage at SoCalGas’ Aliso Canyon natural gas storage facility continues to be restricted after one of the worst methane leaks in U.S. history in 2015-16.

“Recognizing these restrictions, staff assesses that the risk of service interruptions is lower this winter than in recent winters,” CEC staff wrote in a briefing paper. “This lowered risk is largely due to forecast demand being lower than in prior years. Specifically, staff projects zero curtailment on a winter day cold enough to occur once in 10 years.”

In colder conditions, SoCalGas might have to curtail 280 million cubic feet per day, a tenth of its total pipeline flow of 2.8 million cubic feet per day, the CEC said. The curtailment would affect “noncore load,” mainly electric generators plus some industrial customers and other users.

“Any adverse event, such as a pipeline going out of service, could lead to a higher curtailment,” the CEC report said. “The key risk to reliability is multiday cold weather events with additional infrastructure outages.”

SoCalGas serves nearly 22 million customers, about the same as the population of Florida, in its 24,000 square mile territory.

The CEC’s review is part of its informational proceeding on decarbonization, which it launched with a workshop in June.

“The Energy Commission is making great strides towards enhancing our modeling and analytical capabilities in this winter assessment,” Chair David Hochschild said at Wednesday’s workshop. “We are using our own gas-demand forecast results for the first time, [and] we’ve been able to dig deeper into the winter demand scenarios. All this leads to more verifiable results that feed into the gas decarb.”

Aliso Canyon

Aliso Canyon, regarded as both a threat to public safety and essential for reliability, has been a sticking point in that effort.

Residents and public officials have repeatedly called for its shutdown after it spewed more than 100,000 tons of gas into the atmosphere. The leak was contained after four months and multiple failed attempts.

SoCalGas and parent Sempra Energy agreed to pay $1.8 billion last year to settle the claims of 35,000 residents who claimed they suffered physically and emotionally from the leak.

In November 2021, California’s two Democratic senators, Dianne Feinstein and Alex Padilla, issued a joint statement saying it is “critical that the California Public Utilities Commission outline concrete steps to close this facility while ensuring the reliability of our power grid.”

The storage facility serves more than 11 million customers and provides fuel to 17 gas-fired plants, according to SoCalGas.

“It is a critical part of the region’s energy infrastructure,” the utility says on its website. “More than 90% of Southern Californians depend on gas for heat and hot water, and approximately 60% of all the electricity generated in California is made by natural gas-fired power plants.”

Last November, the CPUC increased Aliso Canyon’s storage limits from 34 billion cubic feet to 41 billion cubic feet because of reliability concerns — still well below its pre-leak capacity of 86 Bcf. Climate change-induced extreme weather “unfortunately has created greater short-term dependency on natural gas generation,” former Commissioner Martha Guzman Aceves said at the time.

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FERC Approves PJM Plan to Speed Interconnection Queue

FERC on Tuesday approved PJM‘s proposal to speed up its interconnection queue by handling requests through a new clustered approach that prioritizes projects that are ready to build (ER22-2110).

Under the new paradigm, PJM will shift away from its current first-come, first-served methodology to instead study new service requests with a first-ready, first-served approach that clusters proposed projects together to determine network impacts and allocate network upgrade costs. Much of the backlog of submitted projects will be grouped into transitional cycles, which are expected to be completed in the fourth quarter of 2026.

PJM Vice President of Planning Kenneth Seiler said the RTO sees FERC’s Nov. 29 order as a win for interconnection customers, stakeholders and electric users by allowing projects to more quickly move through the queue and begin development. He credited the transparency and dialogue with stakeholders through the process of drafting the proposal with creating a solution that was accepted by the commission nearly unaltered.

“We’re very happy with how FERC has come forward with this,” Seiler said.

An Aug. 30 deficiency notice from the commission seeking more information from PJM did not affect the anticipated timeline for implementing the new transitional process, Seiler said, and staff will be discussing the next steps at the Dec. 6 Planning Committee meeting. (See FERC Issues Deficiency Letter on PJM Queue Overhaul.)

“I believe we’re well on track to move forward,” he said.

Signing off on Tuesday’s order were commissioners James Danly, Mark Christie, Willie Philips and Allison Clements, who wrote a concurrence. Only Chair Richard Glick did not participate in the order; FERC’s Division of Media Relations could not supply a reason for his non-participation.

The order also requires two compliance filings from PJM. The first, due within 30 days, calls for new tariff language codifying that only new service requests with no network upgrade costs and that do not require further studies can receive acceleration to a final interconnection-related agreement.

The second filing is due 60 days before PJM begins to study interconnection requests under its new rules, after the completion of the transitional studies.

PJM is also required to submit informational reports alongside its Order 845 filings during the transitional period, detailing its progress toward reducing the backlog. The reports are to include the number of studies completed, average completion time, the number remaining in each cycle queue and updated timelines on when the RTO expects to begin and complete each phase.

Approval Paves Way for New Rules and Transitional Process

PJM has argued that the queue changes were needed as the number of new service requests tripled from 2019 through 2022, with more than 2,700 active projects as of May 10. In a letter accompanying filing, the RTO said the current interconnection process doesn’t provide incentives for speculative projects to leave the queue in timely fashion. When such projects exit the queue late in the process, they trigger restudies impacting the cost allocation for other submissions further down the queue.

Shifting from a process of studying and allocating costs for each project individually, the new approach groups projects into clusters and conducts studies in three phases, with an increasing share of a readiness deposit required at each step equal to a portion of the network upgrade costs.

Deposits vary with the size of a project, ranging between $75,000 and $400,000. There will be “off-ramps” — or decision points — between each phase for developers who wish to discontinue their projects and partial refunds of the deposits.

Developers also are required to show evidence of site control, with escalating degrees required the further a project has progressed through the three phases. Currently, developers are only required to demonstrate site control once when submitting a project and only for the generator site.

For two queue cycles, projects that entered the queue between April 2018 and September 2021 will be studied under transitional rules, while projects valued under $5 million will be subject to a “fast track” process. PJM will begin to conduct studies under the new rules after completion of both the transitional cycles and the fast-track process.

Many protestors raised concerns about the potential for the fast track to allow less mature — and possibly speculative — projects to jump the queue over more mature, higher-cost projects. Protestors also complained that the $5 million threshold was arbitrary and that the readiness deposits are insufficient to weed out speculative submissions. (See Renewable Devs Criticize PJM Response to FERC on Queue Proposal.)

But FERC found that the interconnection rule changes strike a balance of allowing PJM to expedite its ballooning interconnection backlog, helping developers progress their projects toward construction, and letting mature projects continue under the current rules.

“PJM’s proposed transition mechanism is a reasonable means of implementing PJM’s queue reform proposal and reasonably balances the interests of completing the interconnection study processes for mature New Service Requests under PJM’s current rules with the need to move expeditiously to a first-ready, first-served clustered cycle approach in order to clear the significant backlog and begin full implementation of the New Rules,” the commission wrote in its order.

“We recognize that PJM’s proposed queue cycle cutoffs for use of the current rules and the Transition Period Rules will inevitably exclude certain interconnection customers, but, as the commission has pointed out in multiple queue reform proceedings, ‘any cutoff date inevitably will have that effect.’”

Operational Penalties Eliminated for Late Tx Service Request Studies

The approved proposal also removes tariff language outlining penalties for transmission studies that are not completed on time, which PJM argued is now unnecessary given that FERC Order 845 requires that failures to meet study deadlines be publicly reported to the commission.

Protestors contended that removing the language would contradict the commission’s interconnection notice of proposed rulemaking and said the provision would lengthen delays for firm transmission service customers. But FERC determined that removal of the tariff language meets the requirements of Order 890, as the penalties “would not necessarily target delays due to studying firm transmission service requests.”

Clements Concurs Reluctantly

Clements issued a concurring opinion in which she expressed reluctant support for approving PJM’s proposal, which she described as an imperfect solution to an interconnection queue that has “spiraled out of control.”

Clements was most concerned about the requirement that developers demonstrate 100% site control for interconnection facilities at the decision point at the end of the third study phase. She noted that commenters’ protests raised the possibility that viable projects could be removed from the interconnection queue, particularly should a generation-owning transmission owner direct a late-stage route change to force a project out of the queue.

“They argue that the site control requirement may prove to be too onerous in practice because gen-tie line sites may involve numerous small land parcels for which minor issues could come up, and because last minute changes in line routes may occur. PJM’s untested approach appears to be unique among RTOs,” she said.

Clements’ also expressed concerns about the elimination of penalties for transmission service request studies that do not meet their deadlines, a revision she said only complies with the commission’s Order 890 due to the “unique circumstances of PJM’s interconnection process.”

To create an interconnection process that meets the needs of customers, she said the approved proposal should be viewed as “one step upon which several others could conceivably be layered.” She encouraged PJM and other RTOs to consider implementing forward-looking study processes that would provide those applying for interconnection with a more information that is less prone to unpredictable changes based on changes to the queue.

“Further changes that hold potential to accelerate PJM’s interconnection queue include modifying the threshold at which network upgrades are triggered by the interconnection process, and adjustments to cost allocation for interconnection upgrades such that network upgrade costs are less likely to spur queue withdrawal,” she wrote.

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NECEC Scores Another Victory in Maine’s Highest Court

Maine’s high court on Tuesday issued another favorable ruling for the New England Clean Energy Connect (NECEC) transmission project, increasing the possibility that the contentious line will be resurrected.

The decision by the state’s Supreme Judicial Court marks the second in favor of the project since August, when it found that a referendum blocking the project may have been unconstitutional. (See Maine Court Ruling Gives New Life to Contentious Transmission Line).

In Tuesday’s order, the court reversed an August 2021 decision by the state’s Business and Consumer Court to vacate a lease agreement for public lands between the Maine Bureau of Parks and Land (BPL) and Central Maine Power, NECEC’s developer.

The court said that the BPL had followed the appropriate process in approving the lease, and found that Question 1, the referendum Maine voters approved in 2021 to oppose the project, had not vacated the lease.

“Because we conclude that the evidence contained in the record is sufficient, we see no reason to impose a further burden on the parties’ time and resources by remanding for the Bureau to take further evidence,” the five-judge panel wrote. “We conclude that the record establishes that the Bureau acted within its constitutional and statutory authority in granting the 2020 lease.”

Together, this week’s ruling and the August one mark significant victories that could put the project back on track.

“We think these two decisions have resuscitated the viability of the transmission project,” ClearView Energy Partners said in a note to clients.

A legal fight over Question 1 will continue, with the Business and Consumer Court set to hear more arguments in April as to “whether or not CMP had vested rights to complete construction of transmission line,” according to ClearView.

Depending on how that decision goes, CMP could restart construction as early as mid-2023, or face the prospect of having to make another appeal to the state’s highest court.

“Today’s ruling by the Law Court is yet another step in the right direction for Maine’s renewable energy future,” Scott Mahoney, senior vice president at CMP parent company Avangrid, said in a statement.

NECEC proponents have been arguing for years that the project is necessary to transmit electricity from hydro plants in Quebec down through Maine and into Massachusetts.

“The serious need for the NECEC project to reduce our reliance on fossil fuels, combat climate change, and lower regional energy prices remains unchanged,” Mahoney said.

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Ohio Lawmakers Envision a State Nuclear Development Authority

Ohio lawmakers appear to be on track to create a nuclear development authority that would promote the state as a center for companies seeking to develop small modular and other advanced reactors and engage in related nuclear research.

The effort stems from House Bill 434, which was introduced in September 2021, approved by the Ohio House on a 75-to-18 vote in May and referred to the Senate. Backers of the bill testified Tuesday before the Senate Energy and Public Utilities Committee.

Proponents contended that the federal agencies that have dominated expensive nuclear research and development will in the future look to interact with state authorities that organize R&D efforts to attract entrepreneurial nuclear research companies such as TerraPower, which was founded by Microsoft co-founder Bill Gates.

The Washington-based company is focusing on the development of reactors cooled by molten chloride salt, a technology pioneered decades ago at Oak Ridge National Laboratory but abandoned when light-water reactors proved more practical to build given the technology of the day. Proponents of the new authority cited the reactor design as the kind of advanced technology that Ohio ought to be attracting.

William Thesling, an electrical engineer and lifelong Ohio resident, singled out molten salt reactors in his testimony.

“A goal of House Bill 434 is to make Ohio a leading state in advanced nuclear technology research, development and commercialization,” Thesling said.

“This has some enormous long-term benefits for Ohio as a manufacturing state,” he said. “There has been much advancement in materials technology, digital controls, sensors, instrumentation and computer modeling over the past several decades. These gains in technology have allowed us to revisit old technologies that were previously considered to be not viable.  Nowhere is revisiting an old technology more compelling than molten salt reactor technology that was abandoned in the early 1970s largely for political reasons.”

Other proponents argued that U.S. Department of Energy and the Nuclear Regulatory Commission would, under a provision in the 1954 Atomic Energy Act, be obligated to work with a state authority such as what Ohio intends to create.

A spokesman for the NRC had no immediate comment other than that the agency does not normally comment on state issues.  A DOE spokesperson could not be reached.

The next hearing by the Senate committee, which has not yet been announced, will focus on opposing testimony.

HB 434 is the work of Rep. Dick Stein (R), who argued that there has been a change in public sentiment about new nuclear technologies.

“In recent years, there has been a global shift in attitudes toward the development of new nuclear technologies to deploy scalable clean energy,” Stein said in a prepared statement. “This legislation will bring Ohio to the forefront of advanced nuclear innovation and strengthen our domestic supply chains.”

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Montgomery County, Md. Passes Building Electrification Law

Maryland’s largest county on Tuesday passed the state’s strongest building electrification law, requiring most new residential and commercial construction be powered by electricity or other carbon-neutral technologies.

The Montgomery County Council voted to require issuance of the regulations for most new construction by Dec. 31, 2026 (Bill 13-22).

Electrification requirements for residential buildings of four stories or more, affordable housing and schools were pushed back to the end of 2027.

The unanimous vote ended months of negotiations over the bill, which had originally called for the electrification standards to be issued by Jan. 1, 2024, and would also have required electrification for “major renovations and additions.”

The revised deadlines were among a series of amendments to the bill, which in its original form had triggered strong opposition from local builders, Realtors, chambers of commerce and utilities.

Removing the provisions on renovations and additions helped minimize some of the conflict, said At-Large Councilmember Hans Riemer, who led negotiations on the bill as chair of the Planning, Housing and Economic Development (PHED) Committee.

Figuring out “when a house gets triggered to have to transform all its existing systems to electric, when it may have a … gas-burning furnace, that is an extremely difficult process,” Riemer said. “The [county’s] Department of Permitting Services is not there yet, and they need some time.”

The committee also recommended exemptions for buildings that treat sewage or food waste, along with “the cooking portion of restaurants” and other commercial kitchens, such as kitchens in a church or community center. Farming and “farm alcohol production” — specific types of breweries — will also be exempt.

At-Large Councilmember Will Jawando, who co-sponsored the bill with Riemer, called the revised deadlines “a decent compromise. Obviously, we want to move as quickly as we can. … We want to send a strong message, passing this bill unanimously, that we need to move to all electrification. If this helps us get there, I think it’s something that is worth doing.”

Riemer also noted that about three-quarters of commercial buildings in the county are already all-electric, so that the electrification requirement will not hurt the county’s competitiveness for commercial development.

“We’re confident that the private sector is on a path already to make this very feasible for the residential sector,” he added.

Doug Siglin, policy advisor for the Chesapeake Climate Action Network, a local advocacy group, would have liked the council to stick with its earlier deadline, but he still sees the bill as “a very important policy step forward. 

“We didn’t get everything we wanted, but we understand that’s the legislative process,” Siglin said. “In the big picture, we think it’s a hugely important policy.”

Flashpoints

With more than one million residents, Montgomery County is Maryland’s most-populous county and, arguably, its most progressive. The county’s Climate Action Plan calls for an 80% reduction in communitywide greenhouse gas emissions below 2005 levels by 2027 and a 100% reduction by 2035.

The Montgomery County school district also has one of the largest electric bus fleets in the nation. (See Md. County’s Electric School Buses to Provide Synch Reserves for PJM.)

But building electrification and green building in general have long been flashpoints in Maryland, with successive attempts to pass a statewide green building code turned back in the legislature. Most recently, green building provisions in the Maryland Climate Solutions Now Act (SB528) were watered down and replaced with a mandate for the state Public Service Commission to undertake a study on the issue. The PSC’s study, which will include cost and grid capacity evaluations, is to be completed by the end of 2023. Gov. Larry Hogan (R) allowed the bill to become law without his signature. (See Md. General Assembly Sends Climate Solutions Bill to Hogan.)

The building electrification law passed Tuesday represents the council’s attempt to balance the concerns of the county’s business community with its climate goals. In a Nov. 15 report, the PHED Committee said that businesses groups and individuals raised concerns about the law’s impact on housing and building costs and whether the grid would be able to manage the increased capacity electrification would cause.

Other issues included who would pay for needed grid upgrades and the potential for delays in constructing large residential developments.

In an email to NetZero Insider, Pepco (NASDAQ:EXC) spokesman Ben Armstrong said the utility shares “similar decarbonization goals as our communities in Montgomery County.” But he also pointed to the need for the PSC study that would outline “system investments necessary to support an all-electric building code,” while maintaining reliability and affordability for all customers.

“We appreciate the increasing demands on the grid as we partner with the county to electrify and decarbonize more energy sectors,” Armstrong said. “The grid is a dynamic and integral part of enabling carbon reduction, and we are fully committed to supporting those efforts.”

Councilmember Sidney Katz said pushing back the electrification deadlines should give all stakeholders more time. “The timing was such a concern for me, and what [building electrification] does to the grid because the grid does not work on a county-by-county [basis or for] the Washington, D.C. area. It works on a regional basis, and we needed to make certain that what we were doing … would be done with that in mind.”

The Dec. 31, 2026 deadline is the same as in Washington, D.C.’s mandate for new construction to be net zero.

Amendments to the Montgomery County law will also require the county executive to provide the council with a report on the PSC findings by September, 2024.

Still another amendment ensures that the final regulations will not go into effect without “active” approval of the council. Council President Gabe Albornoz said requiring the council’s approval would provide “another check and balance” for any final changes, based on the PSC study or any other analyses.

Fireplaces and Grills

The new law also puts Montgomery County on the front lines of what has become a national debate on whether natural gas hookups should be allowed in new construction. According to the Sierra Club, 68 cities and counties in California have banned natural gas in new construction. A counteroffensive by the natural gas industry has resulted in 20 states passing laws prohibiting such bans.

Maryland has not passed a law prohibiting bans or natural gas hookups.

But issue remains divisive. The only amendment the council did not pass unanimously was a proposal from Albornoz to also exempt residential gas fireplaces and outdoor grills, which he argued are “amenities that are popular among certain home builders and that homeowners are looking for.” Gas fireplaces and grills also produce fewer emissions than wood- or charcoal-fired alternatives, he said.

County officials raised concerns that these exemptions could create a loophole that would allow natural gas hookups in new construction, but Riemer said few would be likely to exploit it. “The expense that would be involved in trying to switch out … a brand new, fully functional, very effective electric heating system with a gas system is probably like the biggest waste of money you could imagine doing as a homeowner,” he said.

But Jawando and Council Vice President Evan Glass spoke against the exemption. “It goes against the meaning and what we’re trying to do here and gives an exemption to people who are the wealthiest and able to do this,” Jawando said. “It’s not good for racial equity and social justice reasons, not good for the intent of the bill.”

Gas-fired fireplaces and grills are “aesthetic amenities,” Glass said. “If the goal of this overall bill is to minimize or quite frankly eliminate some of these uses, then I can’t justify doing it or allowing it just for an aesthetic amenity.”

Councilmember Tom Hucker joined Jawando and Glass in opposing the amendment, which passed on a 6-3 vote.

Councilmember Craig Rice voted for the exemption but also stressed the need for the council to focus on “the reality that many people are living in buildings that continue to suffer from lack of environmental justice, and it will be important for us to make sure that as we continue this onboarding process of electrification, that access is provided to those in our community who are of lower socioeconomic status and who are in existing buildings.”

The positive changes from electrification must be “equitable and accessible to all of our residents,” he said.

CCAN’s Siglin is hopeful that by the time the county releases the regulations at the end of 2026, the definitions of “major renovations and additions” can be clarified. The bill is silent on the issue, which leaves the door open for county officials to “figure out what definitions they want and come back with [them],” he said.

Councilmember Andrew Friedson sees building electrification as inevitably leading to a “conversation about the grid. Ultimately, we need a greener grid, and we have started that conversation in a very public and very substantive way, working collaboratively with industry, with our utilities. We all recognize that for this to make the impact we need it to make, that we want it to make, that a sustainable future requires, we need to have the type of grid that is electric; that doesn’t burn fossil fuels nearly at the extent it is now.”

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ERCOT Says ‘Sufficient’ Capacity to Meet Winter Demand

ERCOT has “sufficient” installed capacity to meet a forecast peak demand of 67.4 GW this winter, the ISO said Tuesday.

Based on its latest seasonal assessment of resource adequacy (SARA), the Texas grid operator expects to have about 87.3 GW of winter-rated capacity available during the upcoming cold months. Two thermal resources, a coal unit and a gas-fired unit comprising 685 MW, will be out of service all season, ERCOT said. The SARA report assumes “typical” thermal outages totaling almost 10 GW this winter.

The projected demand is based on average winter conditions for the 2007-2021 winter peaks that would include the devastating winter storm of February 2021, which still raises Texans’ anxiety levels. The SARA report assumes high demand, high thermal outages and low wind output in its various scenarios but not gas supply disruptions, which FERC and NERC said were responsible for most of the generation outages during the 2021 storm. (See FERC, NERC Release Final Texas Storm Report.)

ERCOT’s demand peaked at 77 GW during the 2021 winter storm before the outages became too much to handle. Texas A&M University’s Texas Center for Climate Studies has said demand would have reached 82 GW had there been enough generation to meet demand.

Pablo Vegas (Admin Monitor) Content.jpgPablo Vegas | Admin Monitor

But Public Utility Commission Chairman Peter Lake expressed optimism about the grid’s preparedness during a joint press conference Tuesday with ERCOT CEO Pablo Vegas. “The lights will absolutely stay on,” he promised.

Lake trumpeted new weatherization requirements and other reliability-focused operational reforms directed by lawmakers following the storm as the reason for his confidence. “We’re better prepared than ever,” he said.

“We are in a position where the elements that are within our control related to the reliability and the operation of the grid are as strong as they’ve ever been going into this winter season,” Vegas said. “The majority of the actions that we’ve taken over the course of this year-and-a-half are designed specifically to address any risk of load-shedding.”

The biggest change has been following up on weatherization requirements placed on generators and transmission facilities. After inspecting weatherization practices last winter at plants that experienced problems during the winter storm, ERCOT staff will check on about a third — or 350 — of the system’s resources this year. Vegas said the ISO plans to complete the inspections early next year.

“Those inspections and audits are showing that the work is getting done to keep those generators operating during the most extreme weather conditions,” he said.

Asked about NERC’s recent winter reliability assessment that found ERCOT’s reserve margin could fall as much as 21% below demand in the most severe scenario, Vegas transitioned to the PUC’s market redesign that is currently underway. (See Proposed ERCOT Market Redesigns ‘Capacity-ish’ to Some.)

“That doesn’t take into account things like winterization,” he said of NERC’s assessment. “We’re not trying to underplay it at all. It does reflect a very low-probability scenario.

“But the fact it exists calls out an issue that needs to be addressed … being able to continue to build dispatchable generation to ensure there will always be enough power. That’s why this [market redesign] work that we’re embarking on is so important,” Vegas added.

He and Lake both used a new message in pointing to the continued growth in ERCOT’s demand. They said Texas is adding a city the size of Corpus Christi — the eighth largest in the state at 317,863, according to the 2020 census — each year, placing additional pressure on developing generation resources.

The PUC’s proposed market designs rely on adding dispatchable thermal resources over intermittent renewable resources.

“We have the same amount of reliable dispatchable resources with no target, no reliability standard, which is a key part of the reforms that this commission has evaluated and discussed,” Lake said. “It’s getting harder and harder to do this, because we have more people … this is a long-term problem, the lack of a reliable reliability standard, but the future is coming.”

ERCOT on Tuesday also released its biannual capacity, demand and reserve report. It forecasts a summer peak demand of 82.7 GW, which would be a new record, and a winter peak of 69.4 GW.

The grid operator said next summer’s planning reserve margin will be 22.2%, a 14-point drop from the 36.2% margin in the May 2022 CDR report.

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FERC IDs Deficiencies in Western RA Program

FERC sent a deficiency letter to the Western Power Pool last week, asking it to provide more information on the tariff filing for its proposed Western Resource Adequacy Program, a first-of-its-kind effort to ensure large swaths of the Western Interconnection have sufficient resources to meet summer and winter peak demand.

The WRAP would have two main “time horizons,” a forward-showing program requiring participants to show they have sufficient capacity months in advance of summer and winter peaks, and an operational program, focused on the allocation of resources in real-time and day-ahead time frames.

The WRAP’s tariff filing said that to participate in the operational program, entities would have to have market-based rate authority to “engage in such transactions to the same extent they would require market-based rate authority if they conducted the same bilateral wholesale transaction for a non-WRAP purpose,” the commission noted.

FERC asked how “participants with market-based rate mitigation or those without market-based rate authority will be treated in the WRAP operations program” and asked WPP to explain “to the extent these procedures are not described in the tariff yet, please describe where WRAP might address the circumstances described above.”

FERC did not give specific examples, but in 2016 it denied Berkshire Hathaway Energy subsidiaries permission to sell wholesale power at market-based rates in four neighboring balancing authority areas, including the PacifiCorp East, PacifiCorp West, Idaho Power and NorthWestern Energy areas. Berkshire had failed to prove that its units did not exercise horizontal market power in the region, the commission said. (See Berkshire Market-Based Sales Restricted in 4 Western BAAs.)

The BHE subsidiaries included PacifiCorp and NV Energy, which together cover much of the interior West. Both have been active in designing the WRAP and are among the 26 participants that signed up for its current non-binding phase, which did not require FERC approval.

Whether FERC might allow the utilities to participate in WRAP with market-based rate authority remains in question. In 2017, the commission gave PacifiCorp and NV Energy permission to sell power into CAISO’s Western Energy Imbalance Market at market-based rates, reversing its previous finding that had restricted the companies to submitting only cost-based offers. That reversal partly hinged on the utilities providing analysis that showed there was little congestion between WEIM BAAs after NV Energy’s energy into the market, supporting the argument that member BAAs should not be considered submarkets subject to market power.  (See PacifiCorp, NV Energy Gain EIM Market-Based Rate Authority.)

Other questions FERC asked WPP to respond to dealt with the WRAP’s requirement that participants secure transmission rights in the forward-showing program and WRAP’s intention to hire an “independent evaluator to provide an independent assessment of WRAP’s performance.”

WPP filed the proposed WRAP tariff with FERC on Aug. 31 and had been hoping to win FERC approval by the end of the year. WPP asked would-be participants to confirm their commitments to the binding phase of the program within the next few weeks. (See Western Power Pool Board Approves WRAP Tariff.)

“While this may alter the timeline for FERC approval of the tariff, it does not change our timeline for securing additional commitment from our participants by mid-December,” WPP CEO Sarah Edmonds said in an emailed statement. “This is an important deadline and next step toward implementing the WRAP and addressing urgent resource adequacy concerns.”

As for FERC’s questions, “we knew this was a possible, if not expected outcome and were prepared for it,” Edmonds said. “These letters are common in complex tariff filings. They simply seek more information and are not a reflection – good or bad – on the merits of the application. Our team is compiling the requested information, and we will respond by the deadline. I remain confident we can resolve the process and ultimately gain approval.”

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PNNL: ‘Households Do Not Make Rational Decisions’ on EE Upgrades

WASHINGTON, D.C. — Neither cost nor environmental impact is the top driver or deal breaker for people deciding whether to make an energy-efficient upgrade to their property, according to a new study from the Pacific Northwest National Laboratory (PNNL).

Rather, the survey of almost 10,000 homeowners and renters across the U.S. found that the comfort and safety of children and pets head the list of motivating factors, with repairing or replacing broken appliances or other equipment a close second, said Chrissi Antonopoulos, a senior analyst at PNNL. Reducing energy bills came in fourth, behind improving their homes’ appearance, Antonopoulos said, presenting the still unpublished survey results at the recent Behavior, Energy and Climate Change (BECC) Conference.

When it comes to residential energy efficiency and electrification — and the Inflation Reduction Act’s billions in rebates for consumers to upgrade their homes — “households do not make rational decisions, and they don’t make decisions based on cost-benefit analysis or something that is going to give them a kickback,” she said.

While consumer education seems to be an effective strategy for motivating energy efficiency upgrades, “technology patterns and behavior and decision-making are really difficult to predict, and we have decades of research and policies to kind of uphold that,” Antonopoulos said.

A joint effort of the American Council for an Energy Efficient Economy and environmental and energy programs at the University of California, Berkeley, and Stanford University, BECC looks at the drivers and roadblocks to individual and community action on climate change. IRA implementation was a central theme at this year’s event, with a special focus on how to ensure low- and middle-income consumers take advantage of the law’s rebates and incentives.

The potential for savings is huge, Antonopoulos said. “Our buildings are woefully inefficient,” she said. PNNL has estimated that about 68% of the U.S. housing stock, 130 million homes, were built before energy codes were widely enacted in the 1990s, she said.

These older homes may have high heating bills because they may not be well insulated and “they have huge HVAC systems … to make them comfortable,” she said.

The PNNL study looks at how to leverage consumer concerns into better energy-efficiency decisions. Safety, health and comfort may be more important in messaging than environmental impact, Antonopoulos said, with the notable exception of HVAC systems, where energy efficiency is a top priority.

“People are installing central air conditioning in huge numbers,” she said. “That is a touchpoint for installing heat pumps. … You’re going to install [air conditioning] anyway; let’s go for a heat pump technology.”  

Space heating accounts for up to 29% of energy costs for many households, according to the U.S. Environmental Protection Agency. Geothermal or air-source heat pumps, which use heat-exchange technologies, can provide more efficient heating and cooling, as well as significant savings. The IRA offers rebates of $2,000 to $8,000 for heat pumps, depending on household income.  

The caveat is that consumers value durability, repairability and low maintenance when replacing HVAC and other systems, Antonopoulos said. Having the latest technology or smart phone app is not a major concern, and contractors can play a huge role. They “have a big influence and can make something go either way, positive or negative,” she said.

Another intriguing finding from the study is that stove preferences appear to be linked to income level. “High-income households tend to prefer gas stoves because they want the super fancy range,” Antonopoulos said. “Lower and moderate incomes tend to prefer electric.

Both homeowners and renters are most likely to adopt “interactive, visible technologies,” like changing to LED lightbulbs, followed by technologies that improve comfort but are “behind the scenes,” like adding insulation or a new hot water heater, Antonopoulos said.

Upgrades with longer-term paybacks, like electrical system upgrades or installing solar panels, are harder sells and made less frequently, she said.

‘Fix the House First’ 

With inflation still high, President Joe Biden is banking on consumers seeing real cost savings from the IRA’s energy-efficiency funding starting in 2023. Speaking to a group of business leaders on Nov. 18, Biden pointed to the 30% investment tax credit for solar, noting it could bring down the cost of installing panels on a residential rooftop by up to $7,500.

“And when you get to keep savings money on your electric bills for the remainder of the year, it’s about $300 a year on average,” Biden said.

But even with effective messaging, low- and moderate-income (LMI) homeowners most in need of those savings may face significant obstacles in accessing the IRA funds, according to several speakers at the BECC conference.

Based on figures from the U.S. Department of Energy, “there are 26 million households in the United States earning less than 80% of the area median income, burning fossil fuels inside their homes today,” said Mark Kresowik, senior policy director at ACEEE, “[For] first-time low-income home buyers, utilities are the third-highest cost that they pay to afford their housing, behind only property taxes and home repairs.”

Many of these homes may need other, more basic upgrades to their roofing or electricity systems before they can even begin to take advantage of the IRA’s energy efficiency rebates.

“Poor housing conditions [are] the most critical and most important barrier that right now is being underfunded in this space,” said David Becker, marketing program manager for energy efficiency at DTE Energy in Detroit. “If we’re going to deliver energy efficiency, if we’re going to deal with historic redlining and historic underinvestment in these communities, we have to address the housing conditions. … When we layer on electrification efforts, solar panels, all those issues, we need to fix the house first.”

In 2020, DTE launched a Health and Safety Pilot with local community groups to identify and repair low-income homes, Becker said. The program, which started with $2 million in funding, has been extended through 2023.

The DTE pilot is upgrading about 300 to 350 homes per year, with roof repairs and electrical system upgrades absorbing the largest shares of home repair dollars, he said.  

DTE has also partnered with two health care nonprofits, the Gilbert Family Foundation and ProMedica, on a $20 million Detroit Home Repair Fund to provide health and safety home repairs for 1,000 homes over the next three years, Becker said.

“This allows us to more deeply impact these homes,” he said. “We can handle trip hazards and grab bars and anything that’s needed in the home [to make] the home healthier.” Following the May program announcement, DTE received more than 120,000 calls about the program in the first 24 hours, Becker said.  

Reducing Barriers

Melanie Santiago-Mosier, vice president for climate, energy and equity at the nonprofit Green and Healthy Homes Initiative, also stressed the need to get low-income households and communities “to the starting point,” where they can take advantage of energy-efficiency funding in the IRA and Infrastructure Investment and Jobs Act.

Her organization sees the federal dollars as a new funding source that can be “braided” with other funding streams, she said, during a keynote panel.

Community engagement upfront is critical, Santiago-Mosier said. “A rebate just kind of implies there’s an initial outlay of money in order to get some money back,” she said. “For a low-income family or an owner of affordable housing, it may be very challenging to actually make that initial investment.”

Henry McKoy, director of DOE’s new Office of State and Community Energy Programs, said the department is trying to close the finance gap with a new $250 million revolving loan fund that will be available to states. Echoing Santiago-Mosier, he also sees an equally critical “information gap” in ensuring people understand what the IRA provisions mean for them.

It “is important for us to make sure we have that outreach, that engagement, those communication channels that actually connect to people and meet people where they are,” McKoy said. “We can’t just look at communities as receivers of services, of benefits. We have to see them as true partners in this work going forward.”

Implementation of the IRA must be “effective, efficient and impactful,” he said. “If we go through this process now where we invest these dollars and at the end of the day we haven’t stood up and invested in institutions that will survive, that will serve as vehicles for this work going forward and that will really be transformational … we will have failed.”

Eligibility Requirements

Dan Burgess, director of Maine’s Energy Office, said meeting people where they are is also a pressing challenge for states, which will be doing much of the difficult work of translating the complex provisions of the IRA so they can be easily understood by homeowners.

He pointed to Maine’s current campaign to install 100,000 heat pumps in homes across the state by 2025, aimed at reducing the state’s reliance on home heating oil. To date, 80,000 heat pumps have been installed, Burgess said.  

“We have reduced barriers and made the program not too complicated. We’ve empowered contractors across the state … and I think it’s working because we’re not requiring folks to jump through 10 hoops.”

IRA rebates for heat pumps will allow the state to build on its own program, he said.

States will also be wrestling with different eligibility requirements and low-income definitions for different provisions of the IRA and IIJA, Kresowik said. Some programs base eligibility on average mean income, while others use the federal poverty level.  

“How [do] you make this easy, so somebody doesn’t have to go through one, two [or] three different income verifications?” he said.

Maine has explored a couple of different approaches to this problem, Burgess said. “You don’t have to provide all of your taxes, but you can provide this page, or you can sign up to allow [the Department Health and Human Services] to provide your information,” he said.

“There are a lot of legal requirements both at the federal level and then oftentimes at the state level,” he said. “I think it’s incumbent on state agencies to work with one another to figure this out, so that it’s as easy as possible for the participants.”

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NERC Calls for Flexibility in CISA Cyber Reporting Rules

Any new cyber incident reporting requirements for critical infrastructure must be carefully drafted to avoid overlap with existing regulations, NERC and the regional entities told the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) in comments submitted earlier this month.

The ERO Enterprise was responding to the request for information that CISA issued in September. The RFI was inspired by the Cyber Incident Reporting for Critical Infrastructure Act of 2022 (CIRCIA), part of the omnibus spending bill passed by Congress and signed by President Biden in March.

CIRCIA requires entities in critical infrastructure sectors — including energy — to report relevant cyber incidents to CISA within 72 hours after they occur, as well as when they make a ransom payment to the perpetrators of a ransomware attack. (See Budget Mandates Cyber Reporting for Critical Infrastructure.)

But authority for defining which incidents are subject to reporting and which additional sectors, if any, are covered by the requirements, along with other details, is left to CISA’s director. The RFI said industry input would help to shape the agency’s final rule.

Worries Over Possible CIP Overlap

In their response, NERC and the REs pointed out that two of NERC’s reliability standards — CIP-008-6 (Cybersecurity — incident and reporting and response planning) and CIP-003-8 (Cybersecurity — security management controls) — require reporting of cyber incidents by various electric industry stakeholders. These requirements are “similar to the reporting requirements set out in CIRCIA,” the ERO said, requiring coordination between NERC and CISA “to ensure harmonization” between the two regimes.

CIP-008-6 requires responsible entities to create cyber incident response plans that they will follow to detect and respond to events affecting cyber systems connected to higher-risk transmission and generation assets, along with control centers. These plans must include reporting of certain cyber incidents to both CISA and the Electricity Information Sharing and Analysis Center (E-ISAC). CIP-003-8 deals with lower-risk transmission and generation assets and similarly requires entities to have response plans that may include reporting incidents to the E-ISAC.

NERC and the REs expressed concern about potential inconsistencies between NERC and CISA’s requirements; for example, CISA’s reporting regulations might have a different timeline for reporting than NERC’s standards, and may require different information. To “avoid duplicative and inconsistent reporting requirements … that could hinder incident response,” the ERO asked that CISA work with NERC and the E-ISAC to ensure the final rule does not cause unneeded friction.

In addition, the ERO drew on its experience with the critical infrastructure protection (CIP) standards to give CISA some advice as it drafts its final rule. The organizations counseled CISA that it should take care in defining “covered cyber incident” and “substantial cyber incident,” as these will play a role in determining what incidents must be reported under the new rules. Care is needed, the ERO said, to ensure these reports produce enough actionable information.

“In developing its incident reporting requirements, the ERO Enterprise initially required entities to report only incidents that had operational impact. … Over the years, however, there were very few incidents reported,” the ERO said. “While receiving few reportable incidents is a positive insofar as it means that there were very few cyber incidents that had an impact on electric utility operations, it could also miss reporting on significant cyber activity, leaving industry unaware of emerging threats and vulnerabilities that have yet to have operational impact.”

While defining reportable incidents too narrowly may prevent the agency from gathering useful data, NERC and the REs said that making the definition too broad would likely result in the opposite problem, with CISA “inundated with reports” that require “significant effort to separate the noise from actionable information.”

Finally, the ERO suggested that CISA’s final rule include “a mechanism for sharing the reports submitted” with the E-ISAC and its counterparts in other critical infrastructure sectors. The organizations pointed out that ISACs are “uniquely positioned … to amplify CISA’s analysis throughout their respective sectors” because of their “established communication mechanisms and protocols.”

If privacy is an issue with sharing sensitive information, the ERO said that CISA can develop a process for either obtaining consent to share such information or removing identifiable data before it is shared.

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IMM Offers Mixed Review of PJM Quadrennial Review Docket

PJM’s Independent Market Monitor offered limited support for major provisions in the RTO’s quadrennial review filing before FERC, while urging the commission to order revisions to some of the proposal’s methodologies and figures (ER22-2984).

In a Nov. 16 filing, IMM Joe Bowring signaled support for PJM’s plan to switch to the use of a forward-looking energy and ancillary services (EAS) offset, rather than relying on historical figures for the calculation, but said the use of long-term financial transmission rights (FTR) is unnecessarily complicated and inaccurate, and cannot be implemented because of the timing of the auctions.

“The more direct, simpler, more transparent, and more accurate approach starts with the forward curves and calculates hourly and nodal forward prices based on historical LMPs, which are a more reliable and more transparent method of calculating locational price differences. PJM should be required to use this approach rather than its proposed approach to the calculation of the forward-looking EAS offset,” the Monitor wrote.

In addition to reducing the overstatement of the net cost of new entry (CONE), and therefore capacity prices, the Monitor said the main benefit of a forward-looking EAS offset would be to better align with how investors look at the market. PJM’s proposal to use FTRs would conflict with that aim, he said.

The Monitor also said the RTO should be required to reconsider the static offset figure should FERC or PJM stakeholders make any significant changes to reactive ancillary service payments, given that revenues from that service factor into the EAS offset. PJM is proposing to set expected revenues using a payment estimate of $2,546 per MW-year.

The Monitor supported PJM’s proposal to calculate net CONE using a combined cycle (CC) power plant as the reference resource instead of a combustion turbine (CT) unit. The filing said that the change better reflects the type of facilities being added to the PJM fleet, noting that no significant number of CTs have been interconnected to the grid since 1999.

With respect to setting the variable resource requirement curve, the Monitor said PJM did not go far enough in its proposal to steepen the slope a quarter of the way towards vertical (effectively purchasing less additional capacity over the expected peak load), suggesting that the curve instead be rotated halfway toward vertical.

If the amount of capacity purchased in the 2023/24 Base Residual Auction was reduced in accordance with the IMM recommendation, a total of $1,790,941,751 in capacity would have been purchased, a decrease of $405,503,039 or 18.5% compared to the actual total of $2,196,444,791, according to IMM estimates. 

“The shape of the VRR Curve directly results in load paying substantially more for capacity than load would pay with a vertical demand curve,” the filing said.

PJM Response

In its response to the Monitor’s filing, PJM told FERC that the market designs drafted in collaboration with the consulting firm Brattle Group would provide the necessary reliability expected in the future. It also noted that the IMM had missed the docket’s comment deadline by nearly a month.

“Brattle cautioned against adopting a curve that is tuned to support exactly a one-in-ten Loss of Load Expectation (“LOLE”) at this time due to the lower net [CONE] and greater fleet turnover than observed in prior quadrennial reviews. In other words, the PJM proposed curve is just and reasonable because it avoids the untenable risk associated with a VRR Curve that barely meets the 0.1 LOLE standard given the current market conditions,” PJM said in its response, filed Nov. 17.

The response also says that many of the IMM concerns regarding the use of FTRs had already been addressed by the commission in its 2019 order on PJM’s Reserve Market Enhancements. (EL19-58)

“In short, the Market Monitor’s concerns with the use of long-term FTR have already been thoroughly litigated and should not be relitigated here,” PJM

Generators Expand on Protests

J-Power USA and the PJM Power Providers Group also filed responses to a PJM retort to their quadrennial review protests before FERC.

Arguing that PJM should use a shorter amortization period within the Commonwealth Edison Locational Deliverability Area (LMP), J-Power said that the RTO has been misunderstanding the Illinois Clean Energy Jobs Act (CEJA) and case law in the state. In its Nov. 18 protest, the company said that under CEJA, the reference resource would be required to cease operations within the amortization period outlined in the filing.

“Like PJM, Brattle improperly conflates the provision of CEJA prohibiting gas-fired resources from increasing their emissions above current levels, which contains an exception for publicly-owned resources, with the separate provision requiring all gas-fired resources to reduce their emissions to zero by January 1, 2045, which has no similar exception.”

Referencing a section of the PJM response detailing how CEJA would allow for a CC unit to remain in operation if needed to provide reliability, J-Power said it is not realistic for large numbers of facilities to be constructed and maintained for that sole purpose. In an affidavit submitted on behalf of J-Power, Paul Sotkiewicz of E-Cubed Policy Associates wrote that there are currently no technologies available to convert a gas-fired unit to run entirely on hydrogen and that current carbon capture and storage capabilities do not meet CEJA requirements.

“A Reference Resource is intended to be a representative example, rather than some kind of exceptional resource. It is downright absurd to imagine that it would be the ‘norm’ for gas-fired resources in Illinois to have to be retained for reliability, or that a rational developer would sink hundreds of millions of dollars of at-risk capital into a resource based on the hope that system conditions will miraculously work out so that the resource is required for system reliability years in the future,” J-Power wrote.

P3, a group that represents PJM power producers, also took aim at the RTO’s choice to use a CC facility as the reference resource, saying that a CT is more reflective of a “pure capacity unit” as opposed to a more frequently dispatched generator.

“By using a combustion turbine as the reference unit, the VRR curve response to changes in energy market conditions is only impacted by net energy revenues projected to be earned during scarcity hours when the combustion turbine operates,” P3’s Nov. 14 response says.

While PJM has not recently seen construction of CTs, P3 argued that the resource type offers a possible solution to the need for flexibility to complement the installation of renewables.

“P3 absolutely concedes and acknowledges that more CCs have been built in PJM than CTs over the last 10 years in PJM. While a historical fact, it says absolutely nothing about the resources PJM will need in the future. PJM’s future needs are going to require flexible units (likely in the form of natural gas and coal) — particularly if there is significant renewable energy penetration,” the group’s filing says.

P3 also noted recent comments by PJM CEO Manu Asthana that that the RTO could see 40 GW of generation in the RTO retire by 2030. With the region’s load expected to increase in the future, the group argued, FERC would undermine reliability by accepting a capacity market built on the assumption that PJM is oversupplied with capacity.

“To P3, this sounds like PJM is indeed on the cusp of a reliability crisis and the impact of the instant filing will coincide directly with the predicted reliability challenges in PJM,” the group wrote.